AFR.L Regulatory News (AFR)

Afren plc

2012 Full Year Results

Record financial results; strong production performance; significant exploration success contributing to reserves upgrade

25 March 2013 - The Board of Afren plc ("Afren" or "the Group") announces results for the

year ended 31 December 2012.

Key highlights

·; Record financial results driven by strong production growth (+123%); FY 2013E net production expected to average 40,000 to 47,000 boepd (excluding Barda Rash)

·; Significant exploration success

- E&A success ratio of 88%

- 265% reserves replacement ratio - net working interest 2P reserves addition of 39 mmbbls (gross 76 mmbbls and excluding Ain Sifni) to 210 mmboe

·; Group pro-forma net 2P reserves expected to increase to approximately 270 mmboe after consolidation of OML 26 reserves

- following exercise of a put option by a third party over FHN shares (subject to shareholder approval)

·; Multi-well E&A drilling campaign targeting Pmean resources of 650 mmboe

- Okwok appraisal success confirms management view of 52 mmbbls gross recoverable reserves (net working interest 29 mmbbls)

- Simrit-3 well confirms eastern extent of anticline

·; Strong balance sheet

- net debt, excluding finance leases US$488 million (31 December 2011: US$548 million)

- US$300m senior secured Ebok facility signed (post period end), replacing the existing Ebok RBL facility. Pro-forma net debt unchanged

·; Repeatable strategy - continue to create significant shareholder value

Commenting today, Osman Shahenshah, Chief Executive, said:-

"In 2012 we achieved record financial results driven by strong production growth at our greenfield developments offshore Nigeria. We realised an E&A success ratio of 88% and a 2P reserves replacement ratio of 265%. We have started our 2013 multi-well E&A campaign with success at Okwok, offshore Nigeria, and Simrit-2 and Simrit-3, in the Kurdistan region of Iraq. With a track record of project delivery, exploration success and strategic acquisitions, we are well placed to continue to create significant value for shareholders."

Analyst Presentation

There will be a presentation to analysts at 09.00 am 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 12:00 pm.

2012 Full Year Results Summary

Record financial results

Afren delivered record financial results in the period driven by strong production growth from the Ebok and Okoro fields, offshore Nigeria, and the benefits of continued high oil prices. Net working interest production in the year increased to 43,059 boepd (including OML 26) representing a year-on-year increase of 123%. During the period, turnover increased by 151% to US$1,499 million (2011: US$597 million) with profits after tax increasing by 62% to US$203 million. Cash flow from operations during the period increased by 177% to US$935 million (2011: US$338 million), equivalent to US$60 per flowing barrel, a level that we believe is sustainable given the pipeline of existing production and appraisal opportunities within our portfolio.

Reserves growth

2012 was a year of excellent exploration success with three significant discoveries announced at the Okoro Field Extension and Ebok North Fault Block, both offshore Nigeria, and at the Ain Sifni PSC, Kurdistan region of Iraq, representing an E&A success ratio of 88%. Our discoveries in Nigeria have added 39 mmbbls of net working interest 2P reserves, representing a reserves replacement ratio of 265% and increase in net 2P reserves to 210 mmboe. By leveraging our fast track development skills and utilising existing infrastructure, we have commenced early production from both the Okoro Field Extension andEbok North Fault Block, both within tenmonths of discovery.

In addition, on 25 March 2013 and subject to shareholder approval, Afren is seeking to consolidate its holding in First Hydrocarbon Nigeria (FHN) following the exercise by a third party of a put option, which will give Afren a 54.8% beneficial interest in FHN. Post accounting consolidation, pro-forma net 2P reserves of the Group are expected to be approximately 270 mmboe. A separate announcement has been released today.

Multi-well high-impact exploration campaign underway

To date, our 2013 multi-well E&A campaign has delivered successful results on the Okwok appraisal in Nigeria and the Simrit exploration wells on the Ain Sifni PSC in the Kurdistan region of Iraq. Both results are expected to further grow our reserves and resources base in 2013.

Drilling on the Simrit-3 well, exploring the eastern extent of the large scale Simrit anticline is continuing. The well is currently operating at 11,483 ft having drilled and logged hydrocarbon bearing intervals in multiple reservoirs. A multi-zone testing programme is being prepared when drilling operations conclude.

At Simrit-2, having achieved a flow rate of 13,584 bopd on test from the Triassic Kurra Chine Formation in 2012, the Partners on the Ain Sifni PSC, completed three additional DSTs in the Mus, Adiayah and Butmah formations yielding incremental flow rates of 5,368 bopd of 21o API. The Partners have now successfully tested six out of twelve zones which in aggregate have yielded flow rates of 18,952 bopd. The remaining testing operations will focus on Upper Jurassic and Cretaceous reservoirs.

In addition, following the successful completion of the three well appraisal campaign across three separate fault blocks at Okwok, the Partners have encountered total net oil pay of 256 ft in the 'D' series reservoirs. At this stage, management estimates gross recoverable reserves of 52 mmbbls (subject to FDP approval). Over the remainder of the year we have further wells planned across the Ebok/Okwok/OML 115 area to de-risk further upside potential that we believe can be rapidly commercialised and developed over the short to medium term.

Capex in line, strong financial position and capital structure

Net debt, excluding finance leases, as at 31 December 2012 was US$488 million (31 December 2011: US$548 million) with cash at bank of US$525 million (31 December 2011: US$292 million). 2012 full year capital expenditure was US$523 million; forecast 2013 capital expenditure is approximately US$620 million.

We are delighted to have signed a US$300 million senior secured Ebok facility, at Libor plus 4-4.8%, with no scheduled repayments until January 2015 (post period end). The facility has been arranged and fully underwritten by BNP Paribas, Citi and Natixis and replaces the existing Ebok RBL facility.

Strategy and outlook

Afren has established leadership positions in each of its three business units, Nigeria and other West Africa, Afren East Africa Exploration and the Kurdistan region of Iraq. With an exciting work programme in 2013 encompassing both established and new basins, we expect to further consolidate our leading position in Nigeria, further demonstrate the quality of our asset base in the Kurdistan region of Iraq and open up new oil and gas basins in East Africa. With numerous opportunities for growth, 2013 promises to be another year of achievement for Afren and we are well placed to continue to deliver superior returns for our shareholders.

Nigeria and other West Africa

Afren is currently producing from its assets offshore Nigeria and Côte d'Ivoire. The portfolio spans the full-cycle E&P value chain of exploration, appraisal, development through to production and is located in in several of the world's most prolific and fast-emerging hydrocarbon basins.

New oil discovery at the Okoro Field Extension

The Okoro-13 well encountered net pay of 549 ft, and test data confirmed the oil to be light and of good quality (38o to 40o API) in excellent reservoir sands with multi-Darcy permeabilities and average porosity of between 30% to 35%. The exploration well was drilled on time and to budget. This discovery at the Okoro Field Extension added c.52 mmbbls of gross 2P volumes to 2011 year-end 2P reserves on the Okoro main field. The discovery is 206% larger than the original Okoro discovery and represents a 2P Okoro reserves replacement ratio in the year of 847%.

In July 2012, Afren and Partner Amni commenced early development drilling at the Okoro Field Extension, just six months from discovery. The Okoro-14 (Okoro Field Extension) development well was drilled by Afren and Amni from the existing wellhead platform (WHP) and delivered rates in excess of 6,000 bopd on production test from the new reservoirs. The well was subsequently completed and brought onstream via the existing Okoro Floating Production Storage Offloading vessel (FPSO) at a stabilised rate of 5,000 bopd of 38° API oil on 31 October 2012. The Partners are firstly utilising the available wellhead slots on the existing Okoro platform to gain early production information that will allow optimal design of the full field development configuration, which could potentially involve up to a further ten production wells.

As part of the Partners' ongoing reservoir management and production optimisation work at the main Okoro field, Afren and Amni successfully side-tracked the existing Okoro-5 production well during Q2 2012. The objective of the side-track well was to access additional oil volumes in a previously un-swept area of the reservoir within the Okoro main field area. The Okoro-5 well was re-entered and side-tracked at a measured depth of 4,481 ft, and the side-track subsequently drilled to a total measured depth of 9,800 ft. The side-track successfully encountered oil pay in the target reservoir, in line with prognosis, and a 2,500 ft lateral drainage section within this pay zone was brought onstream at a stabilised rate of 2,000 bopd.

In 2012, the Okoro field had produced 6.2 mmbbls of oil representing a gross average daily rate of 16,858 bopd and a process uptime of 95.6%. Since production start-up in 2008, the field has continued to perform ahead of expectations, delivering aggregate gross production volumes to end December 2012 of c.26.0 mmbbls, well above the original 2P scenario.

2013 outlook

In 2013, the Partners intend to drill one infill production well/side-track in order to maximise sweep efficiency of the main field reservoirs and also plan to commence fabrication of a new wellhead platform required for the full development of the Okoro Field Extension.

Strong production performance and new oil discovery at Ebok North Fault Block

In 2012, the Ebok field produced 14.1 mmbbls of oil, representing a gross average daily rate of 30,047 bopd and a process uptime of 98.2%, in line with expectations. During early 2012, Afren and its Partner Oriental Energy Resources completed the drilling of two additional producers and one water injection well at the West Fault Block.

The discovery at the Ebok North Fault Block (Ebok NFB) in 2012 has added c.25 mmbbls of gross 2P reserves to 2011 year end volumes, representing a 2012 replacement ratio of 114%. The Ebok NFB well had successfully encountered 370 ft (TVT) of good quality oil in the same Tertiary reservoir sands equivalent to those that have been developed and are in production at the main Ebok field development. The well reached a total depth of 4,230 ft and was targeting a separate fault block structure located approximately 2 km to the north of the main Ebok field.

Post period end, on 21 January 2013, Afren and its Partner Oriental Energy Resources, announced that the Ebok NFB early production well had been successfully drilled, tested and was producing. Performance data from this well will provide important information ahead of implementing an optimal full field development solution.

Creating a 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 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.

2013 outlook

In 2013 the Partners intend to drill three new production wells and a water injection well at the field and to begin installation of the Central Fault Block extension.

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.

Appraisal success at Okwok-10

During the year, the Group completed processing of the 348 km2 Ocean Bottom Cable 3D seismic survey that was acquired over the whole Ebok/Okwok/OML 115 area in late 2011, and the results have been integrated into the existing data set. The new data is assisting with an appraisal programme to determine the optimal development plan for the field. On 24 November 2012, Afren and Partners Oriental and Addax Petroleum spudded the Okwok-10 appraisal well in order to assess additional oil potential within a previously undrilled fault block. The well reached a total measured depth of 4,117 ft and successfully encountered 72 ft of net oil pay in the 'D' Series reservoirs that have proved to be oil bearing elsewhere on the Okwok field and are in production at the nearby Ebok field. The Partners subsequently drilled a planned side-track well and encountered a further 89 ft of net oil pay.

2013 outlook

Drilling on the Okwok-11 side-track well commenced in Q1 2013. The well was drilled to a total measured depth of 3,997 ft and successfully encountered 95 ft of net oil pay in the 'D2' reservoir. The well will now be plugged back and a short section redrilled to enable the reservoir to be fully cored, logged and tested. The newly acquired data together with the results of the Okwok-10 and Okwok-10 side-track wells will be integrated into the field model and used to update the volumetric and optimised Field Development Plan (FDP) prior to submission 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 Ebok Floating Storage Offloading vessel (FSO) located approximately 13 km to the west.

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 Qua Iboe, Biafra and Isongo 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.

2013 outlook

Afren and Partner Oriental plan to spud the first exploration well on the block using the GSF Monitor rig. The Ufon structure remains the most likely target, and is structurally and geologically analogous to the nearby Ebok and Okwok fields but with significant deeper exploration potential. The Partners expect to commence drilling in the second quarter of 2013.

A major redevelopment opportunity with substantial upside

On 1 December 2011, First Hydrocarbon Nigeria (FHN), an Afren associate, 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 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 with Nigerian Petroleum Development Company (NPDC), the oil and gas exploration and production subsidiary of Nigerian National Petroleum Company (NNPC), in the re-development of the block.

During the period, gross average production from the Ogini and Isoko field totalled 6,010 bopd. Production came in below expectations during the period owing to gas-lift compressor outage and maintenance and repair work on the SPDC operated Trans Forcados Trunkline during the first half of 2012. Full gas compression was restored by the end of June 2012, following which production rates of ca. 10,500 bopd were achieved. In order to optimise production from currently active wells, a new 5.2 mmcfd gaslift compressor unit was procured in October 2012 and has been installed, with plans also in progress to install a Lease Automatic Custody Transfer (LACT) unit at the Eriemu manifold. Furthermore, sub-surface and facilities studies are in progress and it is the Partners' intention to finalise the full Ogini FDP by May 2013 and the full Isoko FDP in Q2 2013.

Significant reserves upgrade

An independent assessment of the reserve and contingent resource potential of the Ogini and Isoko fields for FHN in March 2013, has estimated the gross remaining 2P oil reserves at the fields at 134.6 million barrels and gross contingent resources at 68.0 million barrels (gross 2P & 2C reserves and resources 202.6 million barrels; 91.2 million barrels net to FHN). This represents a 231% increase on 2P reserves previously carried by FHN and a 10% increase on previously carried 2P & 2C volumes as at 31 December 2011. In addition, significant upside potential of 144 mmboe also exists within 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.

2013 outlook

The proposed forward work programme consists of the drilling of new horizontal wells in 2013.

On 25 March 2013, Afren announced the proposed consolidation of its interest in FHN, subject to shareholder approval, following the exercise by a third party of a put option over 10.4% of FHN's shares. This will give Afren a 54.8% beneficial interest in FHN. Post accounting consolidation pro-forma net 2P reserves of the Group are expected to be approximately 270 mmboe.

Overview

OPL 310 is located in the Upper Cretaceous fairway that runs along the West African Transform Margin and lies next to the 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.

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

2013 outlook

Detailed technical work and well planning continues in preparation for an exploration well in the first half of 2013.

Overview

OPL 907 and 917 offer potentially attractive Cretaceous opportunities. The main hydrocarbon play consists of late Cretaceous deltaic to shallow marine clastics in fault-related traps.

2013 outlook

We are actively considering our strategic options.

Overview

The JDZ Block 1 extends over approximately 700 km2 in water depths ranging from 5,249 to 5,905 ft. 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.

During the first half of 2012, Total commissioned and completed the drilling of two appraisal wells on the block, the Obo-2 well and the Enitimi-1 well, both encountering oil and gas pay.

2013 outlook

The operator on the block continues to evaluate the results and commercial viability of appraisal drilling undertaken in 2012 on the Obo-2 and Enitimi-1 wells, and possibilities for development.

Production at Block CI-11

Full year 2012 production at Block CI-11 was approximately 4,933 boepd, comprising an oil rate of 807 bopd and natural gas rate of 23.9 mmcfd, in line with expectations.

2013 outlook

We continue to evaluate our strategic and operational options.

Overview

Afren is the sole owner of the Lion Gas Plant (LGP), 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 and delivered 795 boepd average Natural Gas Liquids (NGL) production in 2012, in line with expectations. Production operations continue uninterrupted at the Group's assets in Côte d'Ivoire.

2013 outlook

We continue to evaluate our strategic and operational options.

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 sparse 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.

2013 outlook

Progress is being made to advance the field development plan and agree an associated work programme with Petroci and the Côte d'Ivoire Government. 3D seismic to augment the existing well and seismic dataset is expected to be part of this programme and it is believed that this new data will enhance the prospectivity of this block.

Overview

The Keta Block is located in the Volta River Basin in Eastern Ghana, next to the maritime boundary with Togo. 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.

On 6 February 2012, Afren announced that Eni had commenced drilling of the Nunya-1x (formerly named Cuda-2) exploration well, located in the Keta Block with the Marianas semi-submersible drilling rig. The objective of the Nunya-1x exploration well was to explore a large four-way dip closed Upper Cretaceous structure. On 25 April 2012, Afren announced that the well intersected 502 ft of very good quality sandstone reservoirs, however they were interpreted as water bearing. The well which was drilled to a total depth of 14,928 ft in a water depth of 5,535 ft has provided important information with which to calibrate and further enhance the Group's understanding of this under-explored block in what remains a high-potential basin. The Partners have since progressed into the next two-year exploration phase. As part of the current work programme, the Partners completed the acquisition of new 3D seismic data during Q4 2012.

2013 outlook

The results of the recently acquired 3D seismic survey are being interpreted ahead of the expected drilling of one exploration well in 2014.

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 of the Block.

2013 outlook

Following interpretation of depth processed 2D data on the block, the operator has identified two prospects for exploration drilling, Kolo-1 and Kolo-2. The Kolo-1 well spudded in late February 2013 and is currently drilling ahead. Drilling on Kolo-2 is expected to commence once drilling operations on Kolo-1 have completed.

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 820 ft. The main reservoir objectives are the fluvial and lacustrine sands 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 36º 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 (analogous to Yemen), which could form a secondary exploration play on the acreage.

2013 outlook

In February 2013, the Partners successfully completed the acquisition of 686 km2 of 3D seismic data, which is currently being processed.

Afren East Africa Exploration

Our portfolio of East African assets cover an extensive surface area of 100,221 km2 on a gross basis, and are all located in basins with strong evidence of working hydrocarbon systems being present. We are focused on Cretaceous, Jurassic and Tertiary rift basins which are geological settings that have yielded significant discoveries in Uganda, Sudan, Tanzania, Madagascar, Mozambique and most recently in Kenya.

Following the completion of the Black Marlin acquisition in October 2010, and the ongoing maturing of the portfolio through seismic data acquisition, mean net prospective resources have been upgraded for the East Africa portfolio during the year from 2,113 mmboe to 5,838 mmboe. In addition, new plays have been identified offshore Kenya and Tanzania.

During the period we successfully acquired 3,483 km 2D seismic, 2,262 km2 3D seismic and 1,193 km gravity and magnetic data.

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 with the 850 km of existing 2D seismic coverage. On 5 April 2012, Afren exercised its option to increase its participating interest on the block from 50% to 80% and during the year the Partners commenced and completed the acquisition of 1,900 km of 2D seismic data to firm up the mapped structures and augment the results of airborne gravity and magnetic data acquired in 2011.

Unfortunately, during the seismic acquisition process we recorded our first fatality from a road traffic accident involving one of our seismic contractors. We deeply regret the loss of this life and are very saddened by the effect this tragedy has had on the family involved. Following a full and thorough investigation into the incident, we have further strengthened measures in place to ensure that the required standards of driver training and vehicle safety are met by our contractors across all operations.

2013 outlook

The completion of recently acquired seismic data is expected to further enhance Afren's understanding of the existing prospectivity and facilitate prospect selection ahead of planned exploration drilling in 2014.

Overview

Block 10A is located in the Anza Basin onshore northern Kenya, which is part of the Central African Mesozoic rift system that 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.

Having satisfied all seismic work commitments with the acquisition of 750 km of 2D seismic over the block in 2011, the operator commenced exploration drilling at the Paipai prospect in September 2012.

2013 outlook

On 1 March 2013, the operator, Tullow Oil announced the temporary suspension of the Paipai-1 exploration well. The well which was drilled to a total depth of 13,960 ft encountered light hydrocarbon shows across a 180 ft thick gross sandstone interval. This sandstone is overlain by a 656 ft thick source rock which forms an effective regional top seal. Attempts to sample the initial reservoir fluids were unsuccessful and the hydrocarbonsencountered whilst drilling were not recovered to surface. The well has been temporarily suspended pending agreement on future evaluation options.

Overview

Blocks L17 and L18 are located in the Lamu Coastal Basin, offshore south-east Kenya, covering an area of approximately 1,259 km2 and 3,583 km2 respectively. They are situated in water depths varying from a few feet along the shoreline to up to around 2,625 ft in the Pemba Channel.

There are several potential source rocks for the Tertiary and Cretaceous plays in the southern areas of the basin including the Premo-Triassic Karoo interval sections within the Lower to Middle Jurassic and high Total Organic Counts (TOCs) are recorded within the Eocene section in the Pemba-5 well. 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. The hydrocarbons are expected to have been generated in the deep Pemba trough south of Block L18 and in the Tembo Trough to the east.

In January 2012, Afren completed the acquisition of 1,207 km of additional 2D seismic data targeting the deeper water portion of the blocks. Interpretation of the data has identified four new highly encouraging prospects, in addition to the previously mapped prospects in the shallow water. These prospects represent a major new play with lower risk and greater materiality than the shallow water play, and together have increased mean prospective resources on the blocks from 94 mmboe to 1,088 mmboe, since the Black Marlin acquisition. As a result, Afren, in close consultation with the Ministry of Energy, completed the acquisition of 1,006 km2 3D seismic during December 2012, in lieu of the well commitment, in order to better understand the deep water prospectivity, prior to exploration drilling. In addition, an onshore 2D seismic survey of 120 km was commissioned in September 2012 to simultaneously continue maturation of the shallow water/onshore play; this survey was completed in December 2012.

2013 outlook

The recently acquired 3D and 2D seismic data will be processed and interpreted to further refine the prospect inventory in anticipation of a 2014 drilling programme.

Overview

The Tanga Block is 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.

Interpretation of previously acquired 900 km 2D seismic data reinforced the Partners' views that the prospectivity in the deeper water parts of the acreage represents a potentially lower geological risk exploration opportunity.

2013 outlook

A 620 km2 3D seismic survey was completed in January 2013 and processing is being fast tracked in order to bring the deeper water prospectivity to equal technical maturity as the shallow water prospects and allow the Group to optimise the prospect selection ahead of exploration drilling. Mean prospective resources on the block were upgraded in the period from 1,026 mmboe to 1,244 mmboe.

Overview

In 2012, the Company elected to relinquish Area C in order to focus on high-priority plays in Areas A and B.

Areas A and B are located in the Seychelles micro-continent in shallow to deep water in the northern half of the Seychelles plateau and cover a combined area of approximately 14,319 km2.

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 to 1981, three exploration wells were drilled, all of which encountered oil shows and confirmed the presence of a working hydrocarbon system.

Seismic data previously acquired by the Partners revealed the presence of several large scale structures in the two licence areas that are located in shallow to deep water in the northern half of the Seychelles plateau. A major new 2D survey in Q4 2011 (3,733 km) focused on these areas to better define the areas' true prospectivity.

2013 outlook

In Q1 2013, Afren completed a major 3D seismic programme, the first 3D survey to be conducted in the Seychelles. The programme consisted of two surveys in Afren's licence areas. The first 3D survey was conducted in the southern portion of the licence over the Bonit prospect and covered 600 km2. The second survey was in the northern section of the licence area and covered an area of 2,775 km2. The new 3D seismic combined with existing 2D data are being processed by the Partners to assess in detail the Tertiary, Cretaceous and Jurassic prospectivity.

Gross un-risked prospective resources for the two areas are estimated at 2,800 mmboe.

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. 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.

During the year, the Partners continued to make good progress in meeting the requirements of the expanded work programme as agreed with state oil and gas agency OMNIS in 2011. An airborne gravity and magnetic survey was completed in January 2012, and in June 2012 the Partners conducted geological fieldwork on the block. Acquisition of 230 km of 2D seismic was completed during Q4 2012 and will be used to augment the interpretation of approximately 220 km of previously acquired 2D seismic.

2013 outlook

The expanded work programme combines the first two exploration phases on the block and requires the drilling of one exploration well, expected to be drilled in 2013.

Overview

In 2012, Afren and its Partners decided to relinquish Blocks 2 and 6 in order to focus future exploration activities on Blocks 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 are in the basin and 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.

2013 outlook

Work is ongoing to further interpret the prospectivity of Blocks 7 and 8 ahead of expected drilling by the new operator New Age in the first half of 2013.

Kurdistan region of Iraq

A world-class 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. The field is defined as an elongated anticline with surface expression of 20 km length and up to 7 km width. The reservoirs are fractured carbonates of various depositional settings.

In 2009, the BR-1 discovery well was drilled to 5,535 ft 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. The field is defined by 330 km of good quality 2D seismic data.

In 2012, Afren commenced the phased development of the field, that is initially targeting the development of light oil reserves, the first stage of which comprises of re-entering the three existing wells that have been drilled to date at the field, completing them as production wells and commissioning a modular early production system.

Having commenced an extensive testing programme at the BR-1 well in July 2012 and establishing oil rates in excess of 6,000 bopd of 28° to 32° API oil, as well as obtaining valuable information on the production characteristics of the Mus/Adiayah reservoir, Afren initiated production operations in August 2012 and has produced its first cargo of sales specification oil to tank. Initial storage capacity limits during the early phases of start-up at the field led the Group to restrict flow-to-tank from the well. At year end, approximately 18,800 barrels was held in storage at the field. The work-over and testing operations on the existing Barda Rash well-stock is continuing. The Viking I-10 rig has also been contracted to commence the first of the new Phase 2 wells to be drilled on the block by Afren.

2013 outlook

Afren has commenced Phase 2 operations on the field which will involve new wells to increase production capacity, evaluate new field areas and acquire modern log and core data to better understand and delineate the field.

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 3,642 ft to 10,072 ft 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.

On 17 April 2012, the Group announced that the Simrit-2 exploration well had successfully encountered an estimated 1,342 ft of net oil pay in Cretaceous, Jurassic and Triassic age reservoirs. The well was initially drilled to its prognosed total measured depth of 12,139 ft but was subsequently deepened to a revised total depth of 12,467 ft to test additional zones of prospectivity. The Partners completed drilling on the Simrit-2 exploration well in July 2012. The objective of the well was to test the western extent of the Simrit anticline, a large scale east to west trending structure located on the northern part of the Ain Sifni PSC. Analysis of data collected over the deepened section of well indicated the continual presence of light oil shows, and extended the estimated net oil pay encountered by the well to 1,509 ft throughout Cretaceous, Jurassic and Triassic age reservoirs.

Following the conclusion of drilling operations at Simrit-2, a comprehensive well test programme was undertaken.

The Partners intend to undertake up to 12 separate drill stem tests (DSTs) in total, and announced on 26 July 2012 that the first batch of three DSTs in the Triassic age Kurra Chine formation had yielded an aggregate flow rate of 13,584 bopd of 39° API oil. On 13 March 2013, the Partners announced the successful completion of a further three DSTs at the Simrit-2 well in the Jurassic Mus, Adiayah and Butmah formations yielding an aggregate flow rate of 5,368 bopd and 21° API oil using the Hitech-3 rig. The Partners have now achieved aggregate flow rates of 18,952 bopd to date. The remaining testing operations at Simrit-2 will focus on Upper Jurassic and Cretaceous reservoirs.

Of significance, on 12 September 2012, Afren announced that exploration drilling had commenced at the East Simrit prospect (Simrit-3 well). The Simrit-3 well is located approximately 10 km east of the successful Simrit-2 discovery well, and is exploring the eastern extent of the large scale Simrit anticline. The well is currently operating at 11,483 ft having drilled and logged hydrocarbon bearing intervals in the Cretaceous, Jurassic, and Triassic reservoirs. A multi-zone testing programme is being prepared when drilling operations conclude.

2013 outlook

The Simrit-2 testing programme is on-going and Simrit-3 testing programme will commence shortly. The operator Hunt Oil is also planning to drill a further two exploration wells in 2013 testing the Cretaceous, Jurassic and Triassic reservoirs in the Maqlub structure (Maqlub-1 and Maqlub-2) and a contingent well on Simrit (Simrit-4).

Financial review

"Our financing strategy reflects the resource requirements to execute our business model. The aim is to achieve a balance of operational cash flow with longer term financing to fund capital expenditure. This cyclical cash generation and investment allows sustained growth of the business for longer-term value creation."

1. Result for the year

Revenues

Revenue for 2012 was US$1,499 million, an increase of 151% from 2011 (2011: US$ 597 million). The increase arises from a full year of production from the Ebok field, which contributed US$1,154 million compared to US$272 million in 2011.

Working interest production for the year, including OML 26, was approximately 43,059 boepd, compared to 19,284 boepd in 2011, principally driven by the year-on-year increase in net production from the Ebok and Okoro fields. During the year, production commenced from the Okoro Field Extension.

In 2012, the Group realised an average oil price of US$107/bbl and an average gas price of US$6.3/mcf (2011: US$109.0 per barrel and US$8.8 per mcf), before all royalties. The average Brent price for the period was US$110/bbl (2011: US$109/bbl).

Gross profit

Gross profit for the year was US$756 million, an increase of 150% on the prior year (2011: US$302 million), the increase arising from the full year of production at Ebok and increased production from the Okoro field.

The DD&A charge for oil and gas assets was US$371 million, an increase of 140% on the prior year (2011: US$155 million). The increased charge reflects the higher production achieved by the Group in the year.

The timing of liftings led to a decrease in crude oil stock at the year end, therefore resulting in a charge for stock adjustment of US$6 million, compared with a credit of US$25 million at 31 December 2011.

The Group achieved a normalised operating cost of US$15.0/boe. The decrease from 2011 (US$17.9/boe) reflects efficiencies generated from a full year of production at Ebok. Normalised cost per barrel includes costs and production from the Ebok field from Q4 2011 onwards. All other field costs are included on an annualised basis.

Tax

The income tax charge for the year was US$391 million (2011: US$96 million). The increase reflects the increased profitability of the Group during 2012 and the utilisation of the Group's accumulated tax losses during 2011 to offset tax charges. Of this charge, US$12 million (2011: US$8 million) has been paid in Nigeria. The balance of current tax will be paid in future periods, and the deferred tax liability of US$384 million spread over the life of the Group's assets.

In addition, the Group pays other taxes, in the form of royalties, withholding taxes and non-recoverable VAT locally in the areas in which it operates. In 2012, these amounted to US$166 million (2011: US$167 million).

Finance charges and financial instruments

Finance costs for 2012 were US$73 million (2011: US$57 million). The increase in finance charges relates to issue costs on the Group's second Bond issue in March 2012, as well as the increased interest charge arising from this new issue. The Group capitalised US$59 million of finance charges in the year, largely relating to the development of the Barda Rash field which has been financed using part of the Group's Bond proceeds (2011: US$47 million, largely as part of the financing for the Ebok project).

During the year the Group recognised a loss from derivative financial instruments of US$31 million (2011: US$13 million) relating to crude oil hedging contracts. This reflects a realised loss of US$25 million (2011: realised loss of US$9 million) relating to the premiums paid on the hedging instruments. A further mark to market loss of US$7 million was recorded, relating to the unrealised position on these hedging instruments compared with the oil price as at 31 December 2012 (2011: unrealised loss of US$3 million), reflecting higher expectations of future oil prices than the current hedged position.

Profit for the year

Profit after tax from continuing activities for the year ended 31 December 2012 was US$203 million (2011: US$125 million). Normalised profit after tax was US$244 million (2011: US$125 million). Normalised profit after tax is reconciled to statutory profit after tax in note 8 of the attached financial information.

The impairment charge on oil and gas assets of US$20 million (2011: US$1 million) mainly relates to the write-off of costs of the Nunya well on the Keta Block, offshore Ghana.

Afren's share of losses from its associate investment in FHN was US$7 million in 2012 (2011: US$14 million). FHN reported a loss during the year mainly due to losses arising from crude oil hedging contracts in respect of its share of production from the OML 26 field in Nigeria. This share of losses is offset partly by income received from FHN of US$5 million (2011: US$6 million) in relation to various management and support services provided by Afren to FHN during the year.

2. Financing and capital structure

Operating cash flow

Operating cash flow before movements in working capital was US$1,094 million (2011: US$440 million). After movements in working capital, which included advances and payments to partners of US$100 million relating to field development, and tax payments of US$12 million, net cash generated by operating activities totalled US$935 million (2011: US$338 million, from continuing activities).

The Group's strong operating cash flow is driven by annual production from Ebok, Okoro and Côte d'Ivoire. This cash has principally been used to fund the Group's continued investment in its development, exploration and appraisal activities.

Financing

In March 2012, the Group completed a second Bond issue, proceeds of which were US$300 million before issue costs. The coupon on the bonds is 10.25%, a lower rate than on the January 2011 Bond, 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 Group's US$200 million VTB/BNPP facility which was issued in connection with the acquisition of the Group's interests in the Kurdistan region of Iraq, to fund payments made in December 2011 and March 2012.

Including the March 2012 Bond issue, as well as the January 2011 Bond, the Ebok reserve-based lending facility, and other corporate facilities, gross debt at 31 December 2012 was US$1,013 million, excluding finance leases (2011: US$840 million).

Loan repayments in the period, excluding payments in respect of finance leases, were US$246 million reflecting early settlement of the US$200 million VTB/BNPP facility using the proceeds of the Bond issue in March 2012 and periodic payments due under the Ebok facility. Cash at bank at 31 December 2012 was US$525 million, resulting in net debt (excluding finance leases) of US$488 million (2011: cash of US$292 million; net debt of US$548 million).

Financing outlook

On 22 March 2013, the Group signed the refinancing of its Ebok Reserve Based Lending facility, reflecting the change in status of the project from development into production. The new US$300 million facility, at Libor plus 4-4.8%, increases the amount of capital available and extends the maturity of the Group's outstanding debt. Repayments of the new facility begin in January 2015.

The Group is due to repay its US$50 million unsecured facility during 2013.

3. Development, appraisal and exploration activities

Exploration and appraisal

The Company's investment in exploration and appraisal activities has continued during 2012, with expenditure of US$189 million in the period, excluding amounts relating to the Okoro Field Extension which were transferred to developments assets in the year (2011: US$107 million, excluding the acquisition of the Group's interest in the Ain Sifni PSC).

The main areas of expenditure were East Africa (mainly US$54 million on Kenya Blocks 1, 10A and L17/18, as well as US$16 million on the Tanga Block in Tanzania), and Ain Sifni in the Kurdistan region of Iraq (US$25 million). Exploration outside of these areas largely related to the Keta Block in Ghana (US$23 million).

As noted previously, write-offs in respect of unsuccessful exploration costs were incurred in respect of only one well in 2012, being the Nunya well on the Keta Block, Ghana (charge of US$15 million).

Development expenditure

Expenditure on oil and gas assets was US$273 million (2011: US$469 million), comprising the continuing development of the Ebok and Okoro fields and US$63 million on Barda Rash. In addition, $68 million of costs relating to the Okoro Field Extension were transferred from intangible exploration and evaluation assets to development assets during 2012.

4. Our commitments

The Group has operating and capital commitments as at 31 December 2012 of US$822 million (2011: US$538 million), largely in respect of rig and field equipment leases, and the Group's ongoing exploration and evaluation programmes.

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. At 31 December 2012, the Group's liability in respect of this finance lease is US$117 million (2011: US$136 million), which is being settled in monthly payments of US$2.4 million (including interest) over a seven-year period.

5. Review of our hedging arrangements

The Group's current hedging strategy was put in place in the context of volatile oil prices during early 2011. The Group holds put options which provide minimum floor prices whilst allowing the Group to benefit from most of the upside in oil price movements. The premiums on the options are deferred until maturity.

At 31 December 2012, the Group holds hedges covering approximately 5.0 million barrels of production between the period 1 January 2013 and 30 June 2014, with minimum floor prices on these volumes of between US$80 and US$90/bbl before premiums.

The policy of the Group is to protect its minimum cash flow requirement in a period of a sustained downturn in oil prices. As such the minimum 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 18 to 24 months forward. Based on our current outlook, the hedges above cover approximately 30% of production for 2013 and the first half of 2014.

6. Outlook

The performance of the Ebok and Okoro fields which has contributed to strong financial results and operating cash flows achieved by the Group in 2012 is expected to continue throughout 2013.

The Group will continue to look to fund its exploration and appraisal activities through its operational cash flows, whilst also seeking opportunities to increase its capital strength. In 2013, this includes the refinancing of the Ebok Reserve Based Lending facility.

Group statement of comprehensive income

For the year ended 31 December 2012

Group balance sheet

As at 31 December 2012

Group cash flow statement

For the year ended 31 December 2012

Group statement of changes in equity

For the year ended 31 December 2012

Notes to the Accounts

For the year ended 31 December

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 2013.

The financial information for the year ended 31 December 2012 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 2011 have been delivered to the Registrar of Companies and those for 2012 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 ended31 December 2011.

Afren's production outlook for 2013 and beyond, together with its funding facilities, provides confidence that the Group will continue to generate sufficient working capital for the foreseeable future to enable it to fund its ongoing exploration and development activities.

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 forseeable future. They therefore continue to adopt the going concern basis of accounting in preparing the annual financial statements.

2. Earnings per ordinary share

Earnings per share (EPS) is the amount of post-tax profit attributable to each share.

Basic EPS is calculated on the Group's profit for the year attributable to equity shareholders of US$203.4m (2011: US$121.7) divided by1,080.8 million (2011: 1,016.7 million) being the weighted average number of shares in issue during the year.

Diluted EPS takes into account the dilutive effect of all share options and warrants being exercised.

Where a profit or loss in the period from a discontinued operation has occurred, this profit or loss is factored into the EPS calculation in order to present a Group result from continuing operations. 

3. 2012 Annual Report and Accounts

The Annual Report and Accounts will be mailed on 26 April 2013 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, 11 June 2013 at 11.00 am.

5. Segmental reporting

(a) Geographical segments

During 2012, Afren reorganised its internal reporting structure such that its three previously separate reportable segments in Nigeria, Côte d'Ivoire and other West Africa are now considered to be one single operating and reportable segment. The Group now operates in three geographical markets which form the basis of the information evaluated by the Group's chief operating decision maker: Nigeria and other West Africa, Eastern Africa and the Kurdistan region of Iraq. This is the basis on which the Group records its primary segment information. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group. Comparative information for 2011 has been restated to reflect the above change.

* The majority of the unallocated non-current segment assets was FHN options.

** The majority of the unallocated current segment assets was cash.

*** During 2012, exploration and evaluation additions of US$68.0 million in respect of the Okoro East licence were transferred to property, plant and equipment (PP&E): oil and gas assets in the Nigeria and other West Africa segment.

**** During 2011, exploration and evaluation additions of US$415.4 million in respect of the Barda Rash licence were transferred to property, plant and equipment (PP&E): oil and gas assets in the Kurdistan region of Iraq segment.

Non-current assets in the following segments include:

Revenues were generated in Nigeria of US$1,467.2 million (2011: US$546.8 million) and Côte d'Ivoire of US$31.6 million (2011: US$49.8 million). Included in revenues for Nigeria and other West Africa for the year ended 31 December 2012 are US$1,378 million of sales (2011: US$546.5 million) which were billed to the Group's largest two customers.

(b) Business segments

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

6. Taxation

The Group is subject to various forms of taxation in the countries in which it operates. These include income tax on profits, royalties on production, sales taxes on revenues generated, and payroll taxes on benefits to employees.

(a) Income tax expense

The income tax expense is different from the expected income tax expense for the following reasons:

The application of tax legislation in jurisdictions in which the Group operates can be uncertain and subject to interpretation. Afren calculates the tax charge for the period using the latest information available, taking external advice where necessary, in order to arrive at our best estimate of the final tax position. Revisions to our tax liabilities (either upward or downward) may occur as the Group's tax filings and royalties are agreed with the relevant authorities in future periods.

(b) Deferred taxation

(i) Recognised deferred tax assets and liabilities

The Group's deferred tax assets and liabilities are attributable to the following:

(ii) Unrecognised deferred tax assets

At the balance sheet date the Group also had tax losses (primarily arising in the UK) of US$141.3 million (2011: US$98.3 million) in respect of which a deferred tax asset has not been recognised as there is insufficient evidence of future taxable profits against which these tax losses could be recovered. Such losses can be carried forward indefinitely.

The Group had temporary differences of US$12.5 million (2011: US$2.3 million) in respect of share-based payments, property, plant and equipment and pensions in respect of which deferred tax assets have not been recognised as there is insufficient evidence of future taxable profits against which these tax losses could be recovered.

Deferred tax has not been recognised on undistributed earnings of subsidiaries as the largest proportion of dividends would be from subsidiaries where no additional tax would be applied on dividend income.

7. Share capital, share premium and merger reserve

This section explains material movements recorded in shareholders' equity that are not explained elsewhere in the financial statements. The movements in equity and the balance sheet at 31 December 2012 are presented in the consolidated statement of changes in equity.

(i) In 2011, the provisions of the Companies Act 2006 relating to Merger relief (s612 and s613) were applied to the equity raising through a cash box structure, resulting in the creation of a merger reserve, after deducting the cost of share issue of US$3.4 million. The so called 'cash box' method of effecting an issue of shares for cash is commonplace and enabled the Company to issue shares without giving rise to any share premium.

(ii) Non-cash shares were issued to eligible staff members on maturity of the 2009 LTIP.

8. Reconciliation of profit after tax to normalised profit after tax

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

The table below reconciles the IFRS profit after tax to the normalised profit after tax:

9. Post balance sheet events

On 22 March 2013 Afren signed a new US$300 million Ebok facility which has a three year term and bears interest at Libor plus4-4.8%. The facility will be used to refinance the existing RBL facility amount of approximately US$185 million as well as fundongoing capital expenditure and general corporate requirements including intra group loans.