Afren : 2013 Full Year Results

Afren plc

2013 Full Year Results

Record revenues and cash flows; production ahead of guidance, continued exploration success and significant balance sheet strength

27 March 2014 - The Board of Afren plc ("Afren" or "the Group") announces its results for the year ended 31 December 2013

·      Strong production of 47,112 boepd drives record revenue (US$1.6 billion) and cash flow (US$1.2 billion); 2014E gross production expected to average 62,000 bopd (approximately 40,000 bopd net)

·      Targeting double digit growth in net production over the next five years

·      201% 2P reserves replacement ratio in 2013; including Okwok 2P reserves addition of 46.6 mmbbls (26.4 mmbbls net)

·      Ogo - the third largest global discovery in 2013; P50 resources estimated at 774 mmboe; moving forward with appraisal programme

·      Large existing opportunity set; allocating 2014 capex (estimated US$845m) to highest cash return projects and further exploration drilling

·      12 month E&A campaign targeting over 1,200 mmboe in net prospective resources

·      Net debt of US$ 739 million; balance sheet strengthened with extended debt maturity, lower cost of debt and improved deferred tax position

·      Award of five-year tax exemption in relation to Ebok

Commenting today, Osman Shahenshah, Chief Executive, said:

"2013 has been another excellent year for Afren, with a combination of record revenues and cash flows, production ahead of guidance and industry leading exploration success. The highlight of our exploration campaign was the play opening discovery at Ogo, offshore Nigeria, one of the largest global discoveries in 2013. We have continued to grow and de-risk our portfolio with a 2P reserves replacement ratio of 201%.  Looking ahead, we will maintain our strategy of allocating capital to the highest cash return opportunities that will provide the necessary funding to continue to de-risk our material resource base. Supported by a strengthened balance sheet, a track record of project delivery and exploration success, we are well placed to continue to create significant value for our shareholders."

Analyst Presentation

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

The presentation will also be broadcast live at www.afren.com where the accompanying slides will be available. The presentation will be available on playback from 14:00 GMT.

2013 Full Year Results overview

Exceptional E&A success

2013 was another year of exceptional exploration and appraisal success. The highlight for the year was the basin-opening discovery at the Ogo-1 well, located on the OPL 310 license offshore Nigeria. The well encountered light oil and condensate rich gas in the four way dip closed structure and light oil/condensate in the syn-rift with estimated P50 to P10 gross recoverable resources significantly ahead of pre-drill expectations at 774 to 1,180 mmboe respectively. The discovery at Ogo was the third largest discovery globally in 2013 and the largest in Nigeria for a decade . The Partners are in the process of undertaking a detailed marine 3D seismic programme ahead of planned appraisal drilling. Elsewhere in Nigeria, at Okwok, our successful appraisal campaign and recent FDP submission has resulted in net 2P reserves additions of 26.4 mmbbls.

In the Kurdistan region of Iraq, following the world-class discovery at the Simrit-2 well (1,509 ft of net oil pay and aggregate flow rates of 19,641 bopd) in 2012, we completed drilling on the Simrit-3 well, confirming the eastern extent of the Simrit anticline and achieved a cumulative test rate of 6,293 bopd.  The Maqlub-1 exploration well, testing the high potential Maqlub structure on the block is currently drilling ahead, and has encountered hydrocarbons in the Cretaceous and Jurassic reservoirs.

Our E&A success and acquisitions in the year have delivered a 2P reserves replacement ratio of 201 % (including Okwok following FDP approval in January 2014), representing an increase in net 2P reserves from 270 to 286 mmbbls. However, in the year, write-offs of US$88 million were booked in relation to unsuccessful wells at La Noumbi and Kenya Block 10A and other impairments on licences. We have an exciting E&A campaign planned over the next 12 months that will be targeting over 1,200 mmboe in net resources across proven petroleum systems in both established and frontier basins.

Strong production and cash flow

Afren delivered record revenues and cash flows in the period driven by strong production performance from the Ebok and Okoro fields, offshore Nigeria, benefitting from continued high oil prices. Net working interest production in the year increased to 47,112 boepd representing a like-for-like year-on-year increase of 8%. Turnover increased by 5% to US$1,644 million (2012: US$1,571 million) with profits after tax increasing by 151% to US$475 million. Profit before tax decreased to US$318 million (2012: US$569 million) largely as a result of the impairments listed above and shares of joint venture losses booked in the year and additional payables for residual profit interest due on our fields. Cash flow from operations (including movements in working capital) during the period increased by circa 25% to US$1,216 million (2012: US$974 million). Current production levels and growth projects will ensure strong cash flow in 2014 and beyond, although net equity share of production will be reduced by cost recovery at Ebok. In line with our capital allocation strategy we will prioritise our investment towards the highest cash return opportunities within the portfolio that will provide the funding to continue to grow and de-risk our material resource base.

Double digit production growth

Afren is progressing with further development drilling both offshore and onshore Nigeria in 2014, with an additional platform installation on Ebok, moving forward with the Okoro Further Field Development, the Okwok development and additional drilling onshore Nigeria on OML 26.

Strong financial position

Net debt, excluding finance leases, as at 31 December 2013 was US$ 739 million (31 December 2012: US$ 561 million) with cash at bank of US$ 390million (31 December 2012: US $599 million).

During the year the Group successfully extended the maturity of its liabilities and lowered the cost of its debt following the refinancing of the Ebok RBL facility and tender offer and refinancing of our Senior Secured notes.

In addition, we have also significantly improved our forward cash tax position following the award of the Ebok tax exemption which entitles the Partners to a five-year tax exemption starting from mid-2011 to mid-2016. This was awarded at Ebok in recognition of the positive contribution that independents such as Afren have had in working successfully with local indigenous operators to bring marginal offshore fields into production.

2013 full year capital expenditure was US$ 716 million; forecast 2014 capital expenditure is approximately US$ 845 million focusing on the highest cash return projects and further exploration drilling.

Strategy and outlook

Afren has established leadership positions in each of its three business units, Nigeria and other West Africa, East Africa and the Kurdistan region of Iraq. With an exciting work programme in 2014 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, 2014 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

Nigeria and other West Africa contributes the majority of Afren's production, providing valuable funding for our operational and exploration activity. Our portfolio spans the full cycle E&P value chain of exploration, appraisal and development, through to production, and is located in several of the world's most prolific and fast-emerging hydrocarbon basins.

Optimising production and maximising oil recovery

Production operations continue to run smoothly at the Okoro field. Following the successful discovery in early 2012, Afren and Partner, Amni International Petroleum Development Company Ltd. (Amni), commenced early development drilling at the Okoro Further Field Development. The early development well - the Okoro 14 well - continues to produce at stabilised rates of approximately 4,700 bopd.

Total gross production at the Okoro field in 2013 was 6.5 mmbbls of oil, representing a gross average daily rate of 18,041 bopd (year-on-year increase of circa 7%), and a process uptime of 98.6%. Since the start of production in 2008, the Okoro field has continued to perform ahead of expectations, delivering aggregate gross production volumes to end December 2013 of c.32.4 mmbbls, significantly above the original 2P scenario of 26.2 mmbbls, a remarkable achievement for our first green field development project.

During the year, the Partners commenced the Front End Engineering Design (FEED) and development plans for the fabrication of a new wellhead platform and production unit required for the full Okoro Further Field Development. The Okoro Further Field Development Well Head Platform (WHP) will be a conventional four-pile platform, with a single piece jacket and deck capable of accommodating wireline and coil tubing units. The WHP will have 12 well slots capable of holding dual trees, which would enable the platform to host up to 24 wells. The Okoro Further Field Development platform will be located close to the existing Okoro Main wellhead platform and the two will be linked by a bridge. The Partners have decided after careful deliberation to install a new Mobile Offshore Production Unit (MOPU), as close as possible to the Okoro Further Field Development WHP, which will also be linked by a bridge.

2014 outlook

The Partners expect the FEED to be completed and for the project to be sanctioned in H1 2014. The wellhead platform will be in place by Q1 2015 with development drilling commencing in Q2 2015.

Continued strong production performance at the Ebok field

In 2013, the Ebok field produced 12.74 mmbbls of oil, representing a gross average daily rate of 34,910 bopd and a process uptime of 97.8%, in line with expectations.

Following the discovery in 2012, the Partners successfully drilled three production wells and one water injector well into the Ebok North Fault Block (NFB) in 2013. These wells have been tied back to the existing West Fault Block (WFB) infrastructure. The Partners also successfully drilled and brought on stream an additional production well in the WFB. The wells are currently producing at an aggregate rate of approximately 12,000 bopd.

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 reserves 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 low cost and rapid tie-back of production from future potential developments on the acreage.

Beneficial tax terms
During the year, the Partners significantly improved their forward cash tax position following the award of a five year tax exemption from mid-2011 to mid-2016. The award was given in recognition of the positive contribution that independents such as Afren have made working with local indigenous operators to bring marginal offshore fields such as Ebok successfully into production.

2014 outlook
In 2014, the Partners plan to install the Central Fault Block Extension platform and to subsequently drill five production wells and two injection wells from the platform. The Partners are also looking at additional development drilling for the NFB, which will involve drilling development wells from an extended WFB platform with production through to the existing MOPU. Our forward development capex programme at Ebok reflects cost recovery being achieved in 2014 and has been accelerated in lieu of the tax award, and is expected to generate further high margin returns for the Group.

Overview

Okwok is an undeveloped oil field in OML 67,50 km offshore in 132 ft of water and close to the Afren/Oriental owned Ebok development.

Successful appraisal drilling at Okwok-11ST
Following the successful appraisal drilling results in 2012 from the Okwok-10 appraisal well and the Okwok-10 side track well, the Partners successfully drilled one side-track well, the Okwok-11ST in 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 D-2 reservoir. The data acquired, together with the results of the Okwok-10 well (encountering 72 ft of net oil pay in the D-1 reservoir) and Okwok-10 side-track well (encountering 89 ft of net oil pay in the LD ‑ 1B reservoir), were integrated into the field model and used to update volumetric models and optimise a Field Development Plan (FDP), which was submitted to the Nigerian authorities prior to year end.

2014 outlook
In January 2014, the Partners received approval for the FDP for Okwok from Nigerian authorities. Consequently, Okwok has now been reclassified as a reserve, a strong endorsement of the successful appraisal work undertaken by the Partners since acquisition.

The development plan for Okwok comprises the installation of a separate dedicated production processing facility and Well Head Platform (WHP) with an export pipeline for stabilised crude oil tied back to, and sharing, the Ebok Floating Storage Offloading vessel (FSO) located approximately 13 km to the west. The work programme for 2014 includes the finalisation of detailed reservoir models and detailed development well planning and optimisation. The partnership is looking at the option of pre-drilling at least two production wells during the second half of the year, once the wellhead jacket installation has been completed. This wellhead jacket has been fabricated and is currently in transit to the Okwok field area.

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 an attractive opportunity to further capitalise on our extensive knowledge of the area, exploring the same reservoirs that have already proved 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 expect to benefit from cost synergies, lowering the economic threshold for potential new barrels.

2014 outlook
Following the completion of Ocean Bottom Cable 3D Seismic over the whole Ebok/Okwok/OML 115 area, Afren and its Partner, Oriental, are looking to spud the first exploration well during the latter part of 2014. The Ufon and Ameena East structures are both drill-ready opportunities and additional leads are being pursued with new seismic and advanced reprocessing projects underway.

Overview

OML 26 is located onshore Nigeria in Delta State and covers 480 km2. The block has two producing fields - the Ogini and Isoko fields, both of which offer large scale upside through implementation of a phased development programme and three discovered but as yet undeveloped fields (Aboh, Ovo and Ozoro). Significant additional exploration potential has also been defined on OML 26, with estimates of 615 mmboe gross unrisked prospective resources across multiple prospects that will continue to be worked up in parallel to and integrated with development plans.

Following shareholder approval on 20 May 2013, Afren announced on 29 May that it had completed the acquisition of an additional 10.4% beneficial interest in First Hydrocarbon Nigeria (FHN) for a total consideration of US$37 million in cash. Afren now consolidates its holding of FHN's reserves and production as a subsidiary (including prior year comparatives). Its position onshore Nigeria was further strengthened in July 2013, when Afren increased its holding in FHN further by acquiring a beneficial interest in an additional 23.3% taking its total holding to 78.7%.

During the year, gross average production from the Ogini and Isoko fields was 3,472 bopd. Production in 2013 was affected by periodic repairs on the Trans-Forcados Pipeline and delivery lines, as well as start-up issues with the newly installed compressor. Another 5.2 mmscfd compressor was installed and commissioned in December, while the installation of two new 30 kbbls export pumps is in progress. The Lease Automatic Custody Transfer (LACT) unit has been tied-in to the Eriemu manifold and commissioning is ongoing.

The Partners submitted the Ogini FDP on 29 July 2013, and are currently awaiting approvals from the Department of Petroleum Resources. The Ogini FDP consists of the drilling of 37 production wells, executing 13 short-to-medium-term work-overs, installing a new 18" delivery line, two 50,000 bbl/d 3-phase separators, as well as water treatment and disposal facilities.

2014 outlook
The proposed work programme following approval of the FDP consists of drilling up to two new horizontal wells and one water injector well in 2014.

In March 2014, the operator of the Forcados Terminal, Shell declared force majeure due to the challenges‎ being experienced in carrying out repairs on the 48" Export Line leak.

Overview

OPL 310 is located in the Upper Cretaceous fairway that runs along the West African Transform Margin. Extending from the shallow water continental shelf to deep water, the block lies in an under-explored basin with a proven working hydrocarbon system. It is also in close proximity to the West African Gas Pipeline (WAGP) which allows gas discoveries to be readily developed. Detailed pre-drill evaluation of the block identified several prospects lying in the same Turonian, Cenomanian and Albian sandstone intervals that have yielded significant discoveries in Ghana and Côte d'Ivoire.

On 14 May 2013, Afren announced the completion of a farm-out agreement with Lekoil Limited, subject to Nigerian Ministerial Consent, in the OPL 310 licence. Under the terms of the farm-out, Afren received a total carry of up to US$50 million in respect of the drilling campaign at the Ogo prospect. Post farm-out, Afren's economic interest in the licence is 40% once Afren and Optimum Petroleum Development Ltd, the operator, achieves cost recovery. Afren provides technical assistance to Optimum in respect of Optimum's obligations under a Technical Assistance Agreement.

World-class exploration success - one of the largest global discoveries in 2013

Afren and its Partners spudded a first exploration well, the Ogo-1 well, in Q1 2013, drilling into a four-way dip-closed structure in the Turonian to Albian sandstone reservoirs, and targeting 78 mmboe of gross P50 prospective resources. The drilling programme included a planned side-track, testing a new play of stratigraphically trapped sediments that pinch-out onto the basement high targeting 124 mmboe of gross P50 prospective resources. In total, the Partners were targeting 202 mmboe of gross P50 prospective resources.

On 26 June 2013, the Partners announced that the Ogo-1 well was drilled to a total measured depth of 10,518 ft (10,402 ft true vertical depth subsea), and encountered a gross hydrocarbon section of 524 ft, with 216 ft of net stacked pay. Following the conclusion of drilling operations at Ogo -1, the Partners spudded the planned side-track, the Ogo-1ST well. The well reached a total measured depth of 17,987 ft (12,050 ft true vertical depth) and encountered hydrocarbon intervals in the same Turonian, Cenomanian and Albian reservoirs that were successfully drilled and logged at the Ogo-1 well. In addition, the syn-rift section encountered a 280 ft true vertical thickness gross hydrocarbon interval.

Based on the well and 3D seismic data, the Partners estimate the P50 to P10 gross recoverable resources range to be significantly ahead of pre-drill expectations, at 774 to 1,180 mmboe respectively across the Ogo four-way dip-closed and syn-rift structures. Additional upside potential is expected in the syn-rift play. The Partners expect the syn-rift to contain a light oil or a condensate rich gas.

Whilst circulating bottoms up at TD, the drill string parted at 3,390 ft and during good progress towards recovery of the drill string from the well bore, the well took a hydrocarbon kick. After the kick was safely controlled, the Partners considered it prudent to move to permanently secure the well.

2014 outlook

Afren and its Partners commenced an extensive 2,716 km² marine 3D seismic programme across OPL 310 and the neighbouring OML 113 licence in March 2014 to complement the existing coverage on the two licences. The seismic programme will establish the full extent of the syn-rift play and further dip-closed structures to the north and east of the Ogo discovery. The Partners expect to commence appraisal drilling following the completion of the seismic programme.

Overview

On 17 July 2013, FHN, a subsidiary of Afren, completed the acquisition of a 16.9% economic interest in OML 113 for a total consideration of US$40 million. OML 113 is in the Dahomey-Benin Basin, offshore Nigeria, and is contiguous to the OPL 310 block.

Background to the Aje discovery
The Aje oil and gas field was discovered in 1996 and is 24 kilometres offshore Nigeria on block OML 113 in water depths up to 1,476 ft. Pending ongoing exploration and appraisal work at OPL 310, the field is estimated to be one of the largest oil fields in Nigeria outside the Niger Delta basin.

Three (Aje-1, Aje-2 and Aje-4) of the four wells drilled on the field have encountered oil and gas in various intervals across the Turonian, Cenomanian and Albian sands, and two (Aje-1 and Aje-2) of the wells have comprehensively tested at commercial rates.

The JV Partners estimate the Pmean contingent resources to be 167 mmboe, principally related to the Aje field, with an additional 205 mmboe of mean prospective resources on the block.

2014 outlook
Post period end, the JV Partners submitted the Field Development Plan (FDP) for the Aje field to the Nigerian Department of Petroleum Resources (DPR). The FDP was approved in March 2014 and is is primarily focused on the development of the Cenomanian oil reservoir. The first phase of development includes two subsea production wells, tied back to a leased FPSO. These wells will most likely comprise the recompletion of the existing Aje-4 well, and a new well drilled to the Aje-2 subsurface location. The FDP envisages first oil commencing in late 2015 with mid-case reserves of 32.4 mmbbls, a Final Investment Decision (FID) is expected to be taken by the JV Partners shortly.

In parallel with the seismic programme at OPL 310, Afren has commenced an extensive 2,716 km² 3D seismic across the two licence areas to better define prospectivity in both licences and in particular the full extent of the syn rift structure encountered at the Ogo discovery. The seismic programme will also assist in the future development of OML 113.

Overview

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

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. Ultimately, the oil and gas pay was evaluated to be sub-commercial and Afren is in the process of withdrawing its participation from the licence.

* Until disposal in August 2013.

Portfolio optimisation - creating value

On 28 August 2013, Afren completed the sale of its net interest in the CI-11 Block and Lion Gas Plant (LGP) to Petroci, realising a provisional profit on disposal of US$25.3million.

The assets had afforded Afren a stable production and cash generative base, but were deemed to be non-core to Afren's operations due to the competing capital demands of other higher return projects in the portfolio. Since acquisition, the two assets had brought the Group net operating cash flow in excess of US$[150] million.

Gross production at the CI-11 Block and Lion Gas Plant averaged 2,864 boepd from 1 January 2013 to 31 August 2013.

* Afren's working interest in the Eland and Kudu fields within CI-525 is 61.875%.

Reallocation of Block CI-01 into CI-523 and CI-525

In Q3 2013, Afren reached an agreement with the Côte d'Ivoire Government regarding the reallocation of the CI-01 Block in which Afren held a 65% interest.

The agreement involves the CI-01 Block (gross area of 1,208 km2) being divided into two new larger blocks, CI-523 (gross area of 1,494 km2) and CI-525 (gross area of 1,221 km2). The new CI-523 Block includes the legacy CI-523 acreage as well as the southern portion of the legacy CI-01 Block, thereby extending our acreage to the south. The new CI-525 Block includes the legacy CI-505 Block and the northern portion of the legacy CI-01 Block, thereby extending our acreage to the north. The new CI-523 Block will be operated by Taleveras Group. The new CI-525 Block will be operated by Afren.

Located along a proven petroleum system along the prolific West African Transform Margin adjacent to the borders of Ghana in the
Tano-Ivorian basin, the new CI-523 and CI-525 blocks significantly increase Afren's existing exploration acreage and upside potential in the region.

2014 outlook

The first three-year exploration phase on both blocks involves undertaking an extensive 1,800 km2 3D seismic acquisition programme in the first quarter of 2014 followed in 2015 by the drilling of an exploration well.

Overview

The Keta Block is in the Volta River Basin in Eastern Ghana, next to the maritime border 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 fields.

On 6 February 2012, Afren announced that Eni had commenced drilling of the Nunya-1x (formerly named Cuda-2) exploration well, 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.

As part of the extended two-year exploration phase, the Partners completed the acquisition of 1,582 km2 3D seismic survey in December 2012, which is currently being interpreted, and will be integrated with data from the Ophir Starfish-1 well and the Nunya-1x exploration well.

2014 outlook
A one year extension to this licensing phase has been granted. The work programme will be decided based on the results of the ongoing seismic interpretation.

Overview

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

2014 outlook

Following completion of drilling operations at Kola-1 and Kola-2 in 2013, the partnership has agreed to a 50% relinquishment of the block and is discussing a possible forward work programme.

Overview

Block 2B is 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, 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.

2014 outlook
In 2013, we acquired 686 km2 of broadband 3D seismic data which has now been processed. The interpretation of this data is currently being finalised.

Afren East Africa Exploration

Our portfolio of East African assets covers an extensive area of over 82,000 km2 located in basins of proved working hydrocarbon systems. We focus on onshore rift basins and Cretaceous/Tertiary plays in the offshore, which are geological settings that have yielded significant discoveries in Uganda, Sudan, Tanzania, Madagascar, Mozambique and most recently in Kenya.

Since the acquisition of Black Marlin in 2010, we have increased our seismic acquisition to 11,506 km 2D seismic and 4,976 km2 3D seismic. This has enabled us to upgrade our mean net prospective resources to 8,501 mmboe. We look forward to continuing our multi well E&A drilling programme in 2014.

Overview

Block 1 is 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 discovered by the Tarbaj 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.

In 2013, we concluded the interpretation of 1,900 km of 2D seismic, which identified leads and prospects and a number of new play concepts. Many of these prospects have successful analogues in the Ethiopian sector of the basin immediately north of Block 1. The new data set has also enhanced our view of the oil prospectivity in the south of this large frontier block.

2014 outlook

The forward plan for the acreage includes shooting 150-250 km additional 2D seismic in the first half of 2014 followed by an
exploration well.

Overview

Block 10A is in the Anza Basin onshore northern Kenya, 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.

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. Following a period of evaluation, the Partners elected to relinquish the acreage in November 2013.

Overview

Blocks L17 and L18 are in the Lamu Coastal Basin, offshore south-east Kenya, covering an area of approximately 4,881 km2. 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 Permo-Triassic Karoo interval, the Middle Jurassic and high Total Organic Carbon (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 and 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 and together have increased mean prospective resources on the blocks, from 94 mmboe to 2,021 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, to better understand the deep water prospectivity prior to exploration drilling. In addition, we commissioned an onshore 2D seismic survey of 120 km in September 2012 to simultaneously continue maturation of the shallow water/onshore play. This survey was completed in December 2012.

Interpretation and rock property studies on the 120 km onshore 2D seismic and the 1,006 km2 offshore 3D seismic are underway. The seismic data has highlighted an expansive shallow-water/onshore trend called the Mombasa High.

2014 outlook

Our 2014 programme includes a planned airborne gravity and magnetic survey followed by additional 2D seismic to help define closures across the Mombasa High in preparation for a two well drilling campaign in 2015.

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 use our regional expertise and knowledge.

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

In early July 2013, Afren initiated seismic interpretation on the 620 km2 3D seismic survey. Afren and its Partners have been simultaneously working up both a shallow-water (Chungwa-1, previously Orpheus) and deeper water prospect (Mkonge-1, previously Calliope). EIA surveys and drilling prognosis have been completed for both the Chungwa-1 and Mkonge-1 wells, which are both ready to drill. In addition the 3D has led to the recognition of an additional deepwater prospect named Nanasi that sits between Chungwa and Mkonge. This is being fast-tracked to provide a third potential well location.

2014 outlook
The Partners are now in the process of securing a suitable rig for the shallow water Chungwa-1 prospect with exploration drilling scheduled for the second half of 2014. The Chungwa-1 well will test Tertiary, Cretaceous and Jurassic reservoirs, targeting Pmean resources of 300 mmbbls of oil. Mean prospective resources on the block are currently 1.9 bnbbls.

Overview

Areas A and B are 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. Between 1980 and 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 their true prospectivity.

In 2013, Afren completed a major 3D seismic programme, the first 3D survey to be conducted in the Seychelles, of two surveys in Afren's licence areas. The first 3D survey was 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. Interpretation of this new 3D seismic is underway. Early results have confirmed pre-3D prospectivity in the southern deep water portion of Area A1.

2014 outlook
Results from the northern deep water 3D are expected imminently and will be evaluated in conjunction with the southern deep water 3D ahead of planned exploration drilling.

Gross un-risked prospective resources for the two areas are estimated at 2,994 mmboe.

Overview

Block 1101 is on the eastern flank of the Ambilobe Basin, onshore northern Madagascar. The block encompasses an area of approximately 11,175 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.

In June 2013, Afren ran a successful field trip across the block with OMNIS, the state oil and gas company, viewing exposures of the probable reservoir targets.

2014 outlook
Additional 2D seismic acquisition and a shallow borehole coring programme are planned for Q2 2014 after the rainy season to enhance our subsurface understanding ahead of exploration drilling. The planned work programme will focus on the Mantalay prospect and the Antso lead.

Gross un-risked prospective resources on the block are estimated at 846 mmboe.

Overview

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

2014 outlook

The Partners spudded the El Kuran-3 well on 13 October 2013 using the Sakson 501 drilling rig.

The drilling programme was expected to test the reservoir productivity in the Adigrat and Hamanlei zones, targeting 100 mmbbls of gross prospective resources. Following hydrocarbon shows, the well was extended below the initial target depth to a new total depth of 11,574 ft to evaluate the deeper Gumboro zone. The well is currently undergoing logging and evaluation to determine the quality of the reservoir and to assess the potential commerciality given the remote location.

Kurdistan region of Iraq

A world-class development project

The Barda Rash PSC is 55 km north-west of Erbil, and holds the 14,015 mmbbls STOIIP and 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. 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 326 km2 of good quality 3D seismic data.

In 2012, we commenced the phased development of the field, initially targeting the development of light oil reserves. Having begun 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/Adaiyah reservoir, we initiated production operations in August 2012. In July 2013, we commenced preliminary crude oil sales from the Barda Rash PSC to the local market. Gross production at the field averaged 639 bopd during 2013.

2014 outlook

Afren has now moved to the second phase of development on the field, which involves drilling new wells to increase production capacity and acquiring modern log and core data to better understand and delineate the field.

The Partners commenced drilling on the BR-5 well in Q1 2013 using the Romfor-23 drilling rig which is currently operating at circa 14,436 ft. They also commenced drilling the BR-4 well in May 2013, using the Viking I-10 rig. The well reached a total depth of 13,800 ft. As part of an ongoing programme BR-4 has tested two horizons in the Triassic Kurra Chine formation at 6,100 bopd and 1,750 bopd respectively. The BR-5 well has intersected a similar hydrocarbon-bearing sequence in the Kurra Chine formation and will be tested in due course. Flow lines and facilities will be updated to bring BR-4 and BR-5 into production during 2014.

Overview

The Ain Sifni PSC is located 70 km north-west of Erbil, and is operated by Hunt Oil Middle East Limited. Drilled on the crest of the Simrit anticline in 2010, the JS-1 discovery well logged continuous oil 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.

On 17 April 2012, the Group announced that the Simrit-2 exploration well had successfully encountered an estimated 1,342 ft of net oil 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 oil shows 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. Operator Hunt Oil completed the Simrit-2 Extended Well Test (EWT) programme during the second half of 2013. Produced crude was trucked to local markets. The Simrit-3 well, exploring the eastern extent of the large scale Simrit anticline, tested a cumulative rate of 6,293 bopd. The well has been configured as a produced water disposal well.

2014 outlook
In June 2013, operator Hunt Oil spudded the Maqlub-1 well testing the high potential Maqlub structure to the south of the block and is currently drilling ahead in the Jurassic reservoirs. To date hydrocarbons have been encountered in the Cretaceous and Jurassic reservoirs as confirmed by wireline, Logging While Drilling (LWD), cuttings and gas data.

Operator Hunt has submitted a declaration of commerciality on the block. Simrit-4 was spudded in early 2014. This well will target the Jurassic and Triassic reservoirs.

Following the success at Simrit, the Partners expect further growth in reserves and resources at Ain Sifni in 2014.

Financial review

We achieved record financial results in 2013, with sales revenue of circa US$1.64 billion and operating cash flow of over US$1.2 billion. In 2014 we will allocate our internally generated capital to the highest return projects and continue to deliver sustainable shareholder value.

1. Result for the year

Revenues

Revenue for 2013 was US$1,644 million, an increase of 5% from 2012 (2012: US$1,571 million). The increase arises principally from increased production from the Ebok field, which contributed US$1,320 million compared to US$1,154 million in 2012.

Working interest production for the year was approximately 47,112 boepd, compared to 43,830 boepd in 2012, principally driven by the year-on-year increase in net production from the Ebok and Okoro fields.

In 2013, the Group realised an average oil price of US$106/bbl (2012: US$108/bbl), before all royalties. The average Brent price for the period was US$108/bbl (2012: US$110/bbl).

Gross profit
Gross profit from continuing operations for the year was US$643 million, a decrease of 19% on the prior year (2012: US$791 million), the decrease principally reflecting additional payables for residual net profit interest due on our fields.

The DD&A charge for oil and gas assets, which reflects levels of production and estimates of future capital commitments, was US$409 million, an increase of 7% on the prior year (2012: US$381 million).

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$9 million, compared with a credit of US$7 million at 31 December 2012. Movements in overlift and underlift balances resulted in a credit to cost of sales of US$33 million, compared to a charge of US$26 million in 2012, reflecting the movement from an overlift to underlift position.

The Group achieved a normalised operating cost of US$14.0/boe. The decrease from 2012 (US$15.6/boe) reflects efficiencies generated from increased production at Ebok and Okoro. Normalised cost per barrel excludes costs and production from the Barda Rash field and certain one-off expenses (including fees in respect of certain licence arrangements and the costs of projects which are not directly related to production operations) and DD&A. All other field costs are included on an annualised basis.

Tax
An income tax credit for the year of US$157 million (2012: income tax charge of US$380 million) includes changes arising from the award of a five-year tax exemption obtained by the company holding the Ebok asset. The tax credit includes reversal of prior year current tax and deferred tax provisions of US$381 million, following the receipt of confirmation that the tax exemption will apply from mid - 2011 to mid - 2016.

The effective tax rate for the Group's other producing assets remained consistent with 2012.

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 2013, these amounted to US$419 million (2012: US$249 million).

Finance charges and financial instruments
Finance costs for 2013 were US$157 million (2012: US$91 million). US$49 million of the increase in finance charges relates to the cost of the partial repurchase of the 2016 and 2019 Bonds which was completed in December 2013. The repurchase was funded by the issue of US$360 million 2020 Bonds, with a coupon of 6.625%, which reduces the expected future Group borrowing costs. The Group capitalised US$42 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 (2012: US$59 million).

During the year the Group recognised a loss from derivative financial instruments of US$47 million (2012: US$60 million). US$31 million of the loss related to crude oil hedging contracts, which comprises a realised loss of US$42 million relating to the premiums paid on the hedging instruments and unrealised gains of US$11 million reflecting the position on these hedging instruments compared with the oil price outlook as at 31 December 2013 (2012: realised loss of US$40 million, unrealised loss of US$20 million). A further mark to market loss of US$15 million was recorded, relating to an interest rate swap which swaps a proportion of our fixed rate debt into floating rate by linking interest payments to the performance of certain indices.

Profit for the year
Profit before tax from continuing operations for the year ended 31 December 2013 was US$318 million (2012: US$569 million). Normalised profit before tax from continuing operations was US$483 million (2012: US$637 million). Normalised profit before tax is reconciled to statutory profit before tax in note 8.

The impairment charge on oil and gas assets of US$61 million (2012: US$15 million) relates to the write-off of costs of Kenya Block 10A, which is to be relinquished, and the Group's share of the cost of Kola-1 and Kola-2 wells at La Noumbi, which were drilled during the year and assessed as commercially unsuccessful. A further impairment has been charged in relation to La Noumbi following the partnership's agreement to a 50% relinquishment on the block.

Profit for the year is also stated after the recognition of US$27 million loss from joint ventures, which principally relates to the impairment of Afren's interest in JDZ following the decision to withdraw our participation from the JDZ Block 1.

2. Financing and capital structure

Operating cash flow

Operating cash flow before movements in working capital was US$1,005 million (2012: US$1,108 million). After movements in working capital, which included advances and payments to Partners, and tax payments of US$58 million (2012: US$12 million), net cash generated by operating activities was US$1,216 million (2012: US$974 million).

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

On achievement of the five-year tax exemption relating to the Ebok field, we agreed to make a payment of US$300 million in order to amend the structure of our partnership on the asset. This payment helped to secure additional cost recovery and future tax benefits relating to the rights to available capital allowances.

Financing
In December 2013, the Group successfully completed a third Bond issue, facilitating an extension of the maturity of its liabilities and reducing the cost of its debt. The proceeds from the new issue were US$360 million, before issue costs, and were used to repay US$247 million of the 2016 Bonds and US$50 million of the 2019 bonds. The coupon on the new 2020 Bond is 6.625%, a significantly lower rate than on the 2016 and 2019 Bonds. All three Bonds in issue are listed on the Luxembourg Stock Exchange.

Gross debt at 31 December 2013 was US$1,129 million which includes the 2016, 2019, and 2020 Bonds, the Ebok reserve-based lending facility, and other corporate facilities, excluding finance leases (2012: US$1,160 million).

Loan repayments in the period, excluding payments in respect of finance leases, were US$510.4 million reflecting part settlement of the 2016 and 2019 Bonds, early redemption of the FHN convertible loan note (US$62.5 million), repayment of the FHN acquisition and development facility (US$101.3 million), and repayment of the Group corporate facility (US$50 million). Cash at bank at 31 December 2013 was US$389.9 million, resulting in net debt (excluding finance leases) of US$739.2 million (2012: cash of US$598.7 million; net debt of US$561.3 million).

Financing outlook
In February 2014, the Group refinanced its OML 26 facility and replaced it with a new US$100 million facility.

3. Development, appraisal and exploration activities

Exploration and appraisal
The Group's investment in exploration and appraisal activities has continued during 2013, with expenditure of US$260 million in the period (2012: US$189 million, excluding amounts relating to the Okoro Further Field Development which were transferred to development assets in the year).

The main areas of expenditure were Nigeria (mainly US$62 million on Okwok, and US$72 million on OPL310 where the Ogo-1 well was drilled), and Ain Sifni in the Kurdistan region of Iraq (US$44 million). Exploration outside of these areas related to ongoing seismic and pre-drilling studies across the Group's East African exploration portfolio.

As noted previously, write-offs in respect of unsuccessful exploration costs were incurred in respect of two wells drilled on the La Noumbi licence in Congo Brazzaville. Cumulative costs incurred on Kenya Block 10A were also written-off, along with the Group's investment in the JDZ Block 1 joint venture, following the decision to relinquish the Group's interest in these blocks.

Development expenditure

Expenditure on oil and gas assets was US$457 million (2012: US$276 million), comprising the continuing development of the Ebok and Okoro fields and Barda Rash.

An additional US$108 million of payments due to Partners were capitalised relating to securing agreement for the Okoro Further Field Development and a package of related benefits due to be spread over the life of the project. Payments for these costs will be made over a number of years, starting late 2014.

4. Our commitments

The Group has operating and capital commitments as at 31 December 2013 of US$781 million (2012: US$716 million), largely in respect of rig and field equipment leases, and the Group's ongoing exploration and evaluation programmes.

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 the upside in oil price movements. The premiums on the options are deferred until maturity.

At 31 December 2013, the Group held hedges covering approximately 5.2 million barrels of production between the period 1 January 2014 and 30 June 2015, with the majority of minimum floor prices on these volumes of between US$90 and US$95/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 net entitlement we would seek to protect with these arrangements is between 25-35% of estimated production for a rolling period of 18 to 24 months forward. Based on our current outlook, the hedges above cover approximately 26% of production for 2014 and the first half of 2015.

6. Outlook

After taking into account the effect of cost recovery at Ebok in 2014, which will result in a decreased net equity share of production from the field, the Group will continue to look to fund its exploration, appraisal and development activities through its operational cash flows, prioritising capital to the highest cash return projects.

Group statement of comprehensive income

For the year ended 31 December 2013

Group balance sheet

As at 31 December 2013

Group cash flow statement

For the year ended 31 December 2013

Group statement of changes in equity

For the year ended 31 December 2013

Notes to the Accounts

For the year ended 31 December 2013

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 2014.

The financial information for the year ended 31 December 2013 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 2012 have been delivered to the Registrar of Companies and those for 2013 will be delivered following the Company's Annual General Meeting. The auditor has reported on these accounts; their reports were unqualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis of matter and did not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

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

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

31 December 2012, with the exception of the following accounting standards which were all adopted as of their effective date which was 1 January 2013:

IFRS 10 Consolidated Financial Statements;

IFRS 11 Joint Arrangements;

IFRS 12 Disclosure of Interests in Other Entities;

IFRS 13 Fair Value Measurement;

IAS 27 (revised) Separate Financial Statements; and

IAS 28 (revised) Investments in Associates and Joint Ventures.

Where necessary the 2012 and 2011 comparatives have been restated to reflect the impact of the adoption of the above accounting standards.

IFRS 9 Financial Instruments had not been endorsed by the European Union as at 31 December 2013 and so has not been adopted early.

Afren's production outlook for 2014 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 foreseeable 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. 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.

Basic EPS from continuing operations is calculated on the Group's profit for the year from continuing operations attributable to equity shareholders of US$478.3 million (2012: US$200.5 million) divided by 1,090.8 million (2012: 1,080.8 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.

Profit for the year used in the calculation of the basic and diluted earnings per share from continuing and discontinued operations (US$m)

The weighted average number of ordinary shares for the purposes of diluted earnings per share reconciles to the weighted average number of ordinary shares used in the calculation of basic earnings per share as follows:

3. 2012 Annual Report and Accounts

The Annual Report and Accounts will be mailed on 29 April 2014 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, 4 June 2014 at 11.00 am.

5. Segmental reporting

(a) Geographical segments

The Group 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, East 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 2012 has been restated to reflect the consolidation of FHN on adoption of IFRS 10. FHN is included in the Nigeria and other West Africa segment. Assets in Cote d'Ivoire, which were sold during 2013, are included in the Nigeria and other West Africa segment for management purposes but have been deducted in a separate column in the analysis below to enable a reconciliation to the income statement. The results of these assets are disclosed as discontinued operations in the income statement.

*   The majority of the unallocated non-current segment assets relate to an amount receivable from Partner in 2012.

**  The majority of the unallocated current segment assets relate to an amount receivable from Partner in 2013 and cash in 2012.

*** 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.

Non-current assets in the following segments include:

Revenues were generated in Nigeria of US$1,644.3 million (2012: US$1,571.4 million). Included in revenues for Nigeria and other West Africa for the year ended 31 December 2013 are US$504.0 million of sales (2012: US$1,378.0 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 credit/expense

The income tax expense represents the sum of tax currently payable and deferred tax, and includes a credit in respect of the reversal of prior year taxes no longer expected to be payable, and recognition of deferred tax assets described further below. The tax currently payable is based on taxable profit for the year. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.

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

During 2013, the Group received clarification of the tax position in respect of its Ebok asset in Nigeria. Afren Resources Limited, the subsidiary which holds Afren's interest in the Ebok asset, will benefit from the award of a five-year tax exemption which is effective from the commencement of commercial production until May 2016. As a result, no income tax will be payable in respect of the 2011-2016 period and therefore the provision for all current tax provided for up to the point of confirming the five-year tax exemption has been reversed in the current period resulting in a current tax credit of US$254.3 million and a deferred tax credit of US$192.7 million. The Group has recognised a deferred tax asset of US$97.5 million, representing the expected future tax benefit of depreciation charged in excess of capital allowances claimed to date.

During 2013, the Group agreed to make payments of US$300.0 million in relation to amending the structure of its partnerships, one of the principal benefits of which is securing future tax benefits relating to the rights to capital allowances available for future utilisation.

(b) Deferred taxation

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit and is accounted for using the balance sheet liability method.

Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the rates of tax expected to apply in the period when the liability is settled or the asset realised.

(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$297.5 million (2012: US$141.3 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$23.3 million (2012: US$12.5 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 note explains material movements recorded in shareholders' equity. The movements in equity and the balance sheet at 31 December 2013 are presented in the Group 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.

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

Normalised profit before 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 before tax from continuing operations to the normalised profit before tax:

9. Post balance sheet events

On 27 February 2014 Afren signed a new US$100 million term loan facility for OML 26. This replaces the OML 26 Facility of US$80 million that existed as at 31 December 2013 which was repaid on 28 February 2014. The new facility has a four year term and bears an interest rate of Libor plus 6.5%. The new facility will be used to fund ongoing capital expenditure, operational expenditure and general corporate purposes with respect to OML 26.

Notes:

- Reserves and resources above are stated on a working interest basis (i.e. for the Nigerian contracts our net effective ultimate working interest based on working interest to payback (50% to 100%) and WI post payback (50%)).

- Proved plus Probable (2P) reserves have been prepared in accordance with the definitions and guidelines set forth in the 2007 PRMS approved by the SPE.

- Contingent resources are those quantities of petroleum that are estimated to be potentially recoverable from known accumulations but for which the projects are not yet considered mature enough for commercial development due to one or more contingencies.

- 2013 production excludes NGL output from the Lion Gas Plant.

- Quantities of oil equivalent are calculated using a gas-to-oil conversion factor of 5,800 scf of gas per barrel of oil equivalent.

- The oil price used by NSAI and RPS Energy for their independent reserve and resource assessments at 31 December 2013 was US$100/bbl flat.

- The Group provides for depletion and amortisation of tangible fixed assets on a net entitlement basis, which reflects the terms of the licenses and agreements relating to each field. 
Total net entitlement reserves were 208.4 mmbbls at 31 December 2013.

- Excludes management estimates of contingent resources at OML 113 (gross 167 mmboe) and additional upside at OML 26 (gross 144 mmboe).

Company Secretary and Registered Office

Elekwachi Ukwu

Afren plc

Kinnaird House

1 Pall Mall East

London SW1Y 5AU

Sponsor and Joint Broker

Bank of America Merrill Lynch

2 King Edward Street

London EC1A 1HQ

www.ml.com

Joint Broker

Morgan Stanley

20 Bank Street

London E14 4AD

www.morganstanley.com

Auditors

Deloitte LLP

Chartered Accountants and Registered Auditors

2 New Street Square

Financial PR Advisers

Bell Pottinger

Holborn Gate

330 High Holborn

London

WC1V 7QD

www.bell-pottinger.co.uk

Registrars

Computershare Investor Services PLC

PO Box 82, The Pavilions

Bridgwater Road

Bristol BS99 7NH

www-uk.computershare.com

Legal Advisers

White & Case LLP

5 Old Broad Street

London EC2N 1DW

www.whitecase.com

Dr Ken Mildwaters

Walton House

25 Bilton Road

Rugby CV22 7AG

Principal Bankers

HSBC Bank PLC

60 Queen Victoria Street

London EC4N 4TR

www.hsbc.co.uk

Afren plc

Kinnaird House

1 Pall Mall East

London SW1Y 5AU

England

T: +44 (0)20 7864 3700

F: +44 (0)20 7864 3701

Email: info@afren.com

Afren Nigeria

1st Floor, The Octagon

13A, A.J. Marinho Drive

Victoria Island Annexe

Lagos

Nigeria

T: +234 (0) 1279 6000

Afren Resources USA, Inc

10001 Woodloch Forest Drive

Suite 600

The Woodlands

Texas 77380

USA

T: +1 281 297 2500

F: +1 281 297 2999

Afren East African Exploration (Kenya) Limited

Delta Corner, Tower B, 8th Floor

Waiyaki Way, Westlands

PO Box 61 - 00623

Nairobi

Kenya

Afren MENA Ltd

Erbil Branch

Building C2

Second Floor

Empire Business Complex

Erbil

Kurdistan region of Iraq

T: +964 (0) 6626 41462