Interim Management Statement

Afren plc (AFR LN)

Interim Management Statement

London, 31 October 2013- Afren plc ("Afren" or the "Group"), (LSE: AFR, FTSE 250 index), announces its Interim Management Statement and financial results for the nine months ended 30 September 2013 and an update on its operations year-to-date 2013, in accordance with the reporting requirements of the EU Transparency Directive. Information contained within this release is un-audited and is subject to further review.

Strong financials, production at the upper end of guidance and continued exploration success.

Afren continues to deliver strong financial results in 2013, driven by the year-on-year 18% increase in net production, principally from the Ebok and Okoro fields, offshore Nigeria. The Group expects to be at the upper end of full year net working interest production guidance (40,000 to 47,000 boepd). Following the play opening discovery and successful drilling results at OPL 310, the Ogo-1 sidetrack has reached total depth and reservoir intervals came in high to prognosis, potentially indicating a larger structure than estimated post the drilling of Ogo-1. In addition, the syn-rift section has encountered a 280' true vertical thickness gross hydrocarbon interval. Based on the positive results, the Partners are progressing with wireline data and testing of the side-track. Exploration wells are drilling ahead in Ethiopia (El Kuran-3) and in the Kurdistan region of Iraq (Maqlub-1).

Financial highlights1

(1) Prior period results have been restated to reflect the consolidation of FHN, following the adoption of IFRS 10 and IFRS 11. Further details are provided in Note 1 and Note 11 of the condensed financial statements

(2) From continuing operations, for further details of discontinued operations see Note 10 of the condensed financial statements

(3) See Note 4 of the condensed financial statements

(4) Operating cash flow before movements in working capital

 Key Highlights

· Year-to-date production of 48,573 boepd (+18% year on year). Full year production expected to be at the upper end of guidance (40,000 to 47,000 boepd).

· Successful exploration track record continues:

- Following play opening discovery at OPL 310, offshore Nigeria, Ogo-1 ST successful and now entering testing phase

- Following the successful Drill Stem Test programme at Simrit-2 on the Ain Sifni PSC, Kurdistan region of Iraq (aggregate flow rates of 19,641 bopd), extended well test operations ongoing

- Completion of drilling at Simrit-3. Cumulative oil rate of 6,293 bopd achieved from DST programme in the Triassic, Jurassic and Cretaceous reservoirs

- Ongoing drilling at Maqlub-1, testing the high potential Maqlub structure adjacent to the producing Barda Rash field

- Ongoing drilling at El Kuran-3 in East Africa, targeting 100 mmbbls of gross prospective resources

· Portfolio optimization:

- Completion of the sale of the CI-11 block and Lion Gas Plant in Côte d'Ivoire to Petroci, realizing a provisional profit on disposal of US$25.3 million

- Agreement reached with Government in Côte d'Ivoire for the reallocation of the CI-01 block (gross area of 1,208 km2) into two new larger blocks, CI-523 (gross area of 1,494 km2) and CI-525 (gross area of 1,221 km2)

· Strong balance sheet and financial flexibility with cash at bank of US$458 million (net debt of US$613 million)

Commenting today, Osman Shahenshah, Chief Executive of Afren plc, said:

"Our strong financial performance, with revenue of US$ 1.2 billion, is underpinned by a year-on-year increase in production of 18 per cent. We expect full year production to be at the upper end of guidance of 40,000 to 47,000 barrels of oil equivalent per day.

We continue to build an excellent exploration track record with more successful wells in Nigeria and the Kurdistan region of Iraq, notably the play opener south of Lagos. I am confident that with our track record of project delivery, exploration success and financial discipline, we are well placed to continue to realise significant value from our existing portfolio and for our shareholders."

Operations Update

(1) Pre/post cost recovery

(2) Includes production volumes to 27 August 2013, the last business day before the completion of the sale of CI-11 & LGP to Petroci

Note: All production data remains subject to reconciliation

Nigeria and other West Africa

Nigeria

OPL 310

Following the discovery of a significant light oil accumulation (216 ft of net stacked pay) at the Ogo-1 well, Afren and Partners Optimum Petroleum Development Ltd and Lekoil Limited commenced drilling on the planned Ogo side-track (Ogo-1ST) testing both the down-dip extension of the four-way dip closed structure at the Ogo discovery and a new play of stratigraphically trapped syn-rift sediments that pinch-out onto the basement high.

The Ogo-1ST reached a total measured depth (TD) of 17,987 ft (12,050 ft true vertical depth) on 6 October. Based on Logging While Drilling (LWD) and mudlogging data (plus wireline data over the Turonian reservoir), the well encountered hydrocarbon intervals in the same Turonian, Cenomanian and Albian reservoirs that were successfully drilled and logged at the Ogo-1 well. All of the reservoir intervals came in high to prognosis, potentially indicating a larger structure than estimated post the drilling of Ogo-1. The LWD and mudlogging data also indicate that the syn-rift section encountered a 280' true vertical thickness gross hydrocarbon interval. Whilst circulating bottoms up at TD, prior to commencing logging operations, the drill string parted at 3,390 ft. Partners are in the process of recovering the drill string from the well bore.

Based on the positive results to date, the Partners believe that wireline data needs to be acquired over the Cenomanian, Albian and Synrift sections prior to selecting zones for testing.

Okoro

Production operations continue to run smoothly at the Okoro field. Gross production at the field averaged 18,214 bopd in the period, representing a year-on-year increase of 17 per cent. The Okoro-14 well, the early production well brought on-stream from the discovery in 2012, continues to produce at stabilised rates of approximately 4,800 bopd.

As previously announced on 23 August 2013, the Partners have 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 bridge linked.

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 be bridge linked.

Ebok

Gross production at the Ebok field averaged 35,102 bopd in the period, representing a year-on-year increase of 22 per cent. During the period the Partners successfully drilled three production wells at the field, two from the North Fault Block (NFB) and one from the West Fault Block (WFB); the wells are producing at an average rate of approximately 3,925 bopd. A water injector well will be spudded shortly to optimise and support the existing producing wells on the North Fault Block.

The Central Fault Block Extension platform is expected to be installed in early 2014, and will target additional reservoirs in the Central Fault Block. The Partners are looking at development options for the NFB, which would likely involve the drilling of development wells from an extended WFB platform and with production achieved through to the existing MOPU.

Okwok

During the first quarter of 2013, the Partners successfully drilled one side-track well - the Okwok-11 side track well. 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 newly acquired data together with the results of the Okwok-10 well (encountering 72 ft of net oil pay in the LD-1 reservoir) and Okwok-10 side-track well (encountering 89 ft of net oil pay in the LD-1B reservoir) 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, which the Partnership is reviewing, comprises the installation of a separate dedicated production processing unit and well head platform tied back to, and sharing, the Ebok Floating Storage Offloading vessel (FSO) located approximately 13 km to the west.

OML 115

Following the completion of Ocean Bottom Cable 3D Seismic over the whole Ebok/Okwok/OML 115, the Ufon structure was identified as the most likely target for drilling. The Ufon structure contains mean gross Pmean prospective resources of 65 mmbbls and is structurally and geologically analogous to the Ebok and Okwok fields but has significant deeper exploration potential. The Partners expect to spud the first exploration well on the block in early 2014 using the GSF Monitor rig.

OML 26

During the nine month period to 30 September 2013, gross average production from the Ogini and Isoko fields was 3,544 bopd (subject to reconciled figures from SPDC, the operator of the export terminal). Production for the period was affected by periodic repairs on the Trans Forcados Pipeline and delivery lines as well as start-up issues with the newly installed compressor. The Partners are in the process of installing another 5.2 mmscfd compressor and have almost completed the installation of a Lease Automatic Custody Transfer (LACT) unit. The Partners have recently ordered new export pumps which they expect will aid in optimising production from the currently active wells.

In July 2013, the Partners submitted the Ogini FDP and are currently awaiting DPR approvals. The Ogini FDP consists of the drilling of 37 production wells, the execution of 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. The Ogini FDP drilling campaign is scheduled to commence in Q4 2013 and will be targeting peak production of 35,000 bbls/d from the Ogini field by 2016. The Isoko FDP submission is expected in Q4 2013.

OML 113

OML 113 is located offshore Nigeria, and is contiguous to the Afren operated OPL 310 block. The Aje field located on OML 113 was initially discovered in 1996. 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. The JV Partners are considering drilling and commencement of early production on the Aje field. Based on the Ogo discovery at OPL 310 there are likely to be some development synergies between the two projects. Also the synrift play which encountered a 280' gross hydrocarbon column in the Ogo well, exists on this block and could deliver significant upside to the Aje project when tested with the drill bit in the near future.

Côte d'Ivoire

CI-11 and Lion Gas Plant

On 28 August 2013, Afren completed the sale of its net interest in the CI-11 block and Lion Gas Plant to Petroci realising a provisional profit on disposal of US$25.3million.  Gross production at the CI-11 block and Lion Gas Plant averaged 4,301 boepd from 1 January 2013 to 31 August 2013.

CI-01

Afren has reached an agreement with the Côte d'Ivoire Government regarding the reallocation of the CI-01 block.

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 continue to be operated by Taleveras Group ("Taleveras"). The new CI-525 block will be operated by Afren. Following this agreement, Afren's and its partners holdings in the two new blocks will be as follows:

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

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 in the region and therefore upside potential. Recent exploration activity in the Upper Cretaceous turbidite fan systems within this basin have yielded commercial success, with discoveries including Jubilee, Enyenra and Ntomme in Ghana and Paon and Independance in Côte d'Ivoire.

The first three-year exploration phase on both blocks involves the undertaking of an extensive 3D seismic acquisition programme, expected to occur concurrently in 2014, followed by the drilling of an exploration well.

Nigeria São Tomé & Príncipe JDZ

Block 1

In 2012, Total completed the drilling of two appraisal wells on the block, the Obo-2 well and the Enitimi-1 well, which encountered oil and gas pay, but at lower levels than pre-drill estimates. Afren is in the process of withdrawing its participation in the licence.

Congo Brazzaville

La Noumbi

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

Ghana

Keta Block

The Partners have progressed into the next two-year exploration phase. A 1,582 km2 3D seismic survey completed in December 2012 is currently being processed. The new 3D seismic is currently being interpreted, integrating data from the Ophir Starfish-1 well and the Nunya-1x exploration well. Next steps will be decided based on the results of the interpretation. The work-programme requires one exploration well to be drilled by May 2014.

South Africa

Block 2B

Processing of the 686 km2 of 3D seismic data acquired this year is progressing. The fast track data is currently being reviewed.

Kurdistan region of Iraq

Barda Rash

On 8 July 2013 Afren commenced preliminary crude oil sales from the Barda Rash PSC to the local market. Gross average production has been ramped up from the initial 1,300 bopd to approximately 2,000 bopd currently.

The Partners commenced drilling on the BR-5 well in Q1 2013 using the Romfor-23 drilling rig which is currently drilling ahead at around 11,266 ft. The Partners also commenced drilling the BR-4 in May using the Viking I-10 rig, which is currently drilling ahead at around 10,853 ft. The wells are testing the Cretaceous, Jurassic and Triassic reservoirs previously identified on the structure.

Ain Sifni

During the first half of 2013, Operator Hunt Oil completed testing of the Simrit-2 well with aggregate flow rates of 19,641 bopd achieved from the planned Drill Stem Test (DST) programme. The Mus/Adaiyah reservoirs are currently being produced as part of an Extended Well Test (EWT) programme to better understand reservoir performance. Produced crude is being trucked to local markets.

The Simrit-3 well, exploring the eastern extent of the large scale Simrit anticline reached a final maximum depth of 12,300 ft in the Triassic Kurra-Chine formation in 1H 2013 encountering hydrocarbon bearing intervals in the Cretaceous, Jurassic and Triassic reservoirs. A multi-zone testing programme has been completed and the well has been configured as a produced water disposal well.

A total of 9 DST's were carried in the Triassic, Jurassic and Cretaceous reservoirs reaching a cumulative rate of 6,293 bopd. Of the 9 tests, the Kurra Chine reservoirs produced at rates of 6,043 bopd 36° API gravity crude oil with 4.1mmscfg/d on a 64/64th choke with a WHP of 645 psi. The test of the Mus/Adaiyah produced 250 bopd of 14°API gravity but confirmed the petrophysical interpretation that an Oil Water Contact (OWC) had been intersected by producing 1,164 bwpd with the oil when flowed to surface. The Cretaceous heavy oil reservoirs did not deliver oil to surface using conventional testing methodology. Reprocessing of the Simrit 3D seismic data is underway so that the well data can be integrated with the updated structural understanding and volumetric estimates upgraded. The rig is currently being mobilised to the Maqlub-2 location.

Operator Hunt Oil spudded the Maqlub-1 well testing the high potential Maqlub structure in June 2013. The drilling programme is expected to last 110 days. The Maqlub structure is located adjacent to the Barda Rash PSC and will be testing the Cretaceous, Jurassic and Triassic reservoirs. The well is currently drilling ahead in the Jurassic reservoirs at 6,995 ft. To date hydrocarbons have been encountered in the Cretaceous and Jurassic reservoirs as confirmed by wireline, Logging While Drilling (LWD), cuttings and gas data.

Afren East Africa Exploration

Kenya

Block 1

Final processed products from 1,900 km of 2D seismic data acquired by Afren were delivered in mid-2013. Six leads and prospects have been identified from this data set as well as 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. Accordingly, in late 2014, Afren will drill the Khorof prospect, a large 4-way dip-closure down-dip of an oil seep.

Blocks L17 & L18

Afren completed processing of the 120 km onshore 2D seismic in June 2013 and on the 1,006 km2 offshore 3D seismic in July 2013. Advanced Seismic Analysis (AVO) of the 3D which began in mid-July was completed in September and this will complement seismic interpretation and rock property studies. Afren has identified numerous leads and prospects and will use the information gathered to help in de-risking the offshore prospects in preparation for a two well drilling programme in 2015. Drilling success in the adjacent Tanga block (Tanzania) will significantly enhance the success in L17 & L18.

Block 10A

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. The Partners have agreed to return to Paipai for testing at a later date dependent on rig availability. Current work on the block includes further evaluation of the well results and a seismic programme to better define basement.

Tanzania

Tanga Block

Following completion of a 620 km2 3D seismic survey in January 2013, Afren received final processing of the dataset in early July and subsequently initiated seismic interpretation, AVO analysis and rock property studies. 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 have completed for both the Chungwa-1 and Mkonge-1 wells and are in ready-to-drill status. The Partners are now in the process of securing a suitable rig for the shallow water Chungwa-1 prospect, which will be the first of the two wells to be drilled commencing early 2014.

The Chungwa-1 well will test Tertiary, Cretaceous and Jurassic reservoirs, targeting P50 resources of 210 mmbbls of oil.

Seychelles

Areas A & B

The Partners are processing the new 3D seismic data, combined with existing 2D data to assess in detail the Tertiary, Cretaceous, Jurassic and Permo-Triassic prospectivity. Fast-track versions of the datasets have now been received and final processing is near completion. Early results have confirmed the pre-3D prospectivity in southern deep water portion of Area A with result from the northern deep water 3D expected in Q4 2013.

Madagascar

Block 1101

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. 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.

Ethiopia

Blocks 7 & 8

Operator New Age spudded the El Kuran-3 well on 13 October 2013 using the Sakson 501 drilling rig, following the slow mobilisation rig up of the drilling unit. The drilling programme is expected to last 45 days and will test the reservoir productivity in the Adigrat and Hamanlei zones, targeting 100 mmbbls of gross prospective resources. Previous drilling on the block at the El Kuran-1 identified gas shows in the Adigrat and a potential oil zone in the Hamanlei.

Exploration and appraisal drilling schedule

(1) Pre/post cost recovery

(2) Following the announcement of the farm-out to Lekoil Limited ("Lekoil") on 14 May 2013, subject to Nigerian Ministerial consent. Economic interest post Afren and Optimum achieving cost recovery.

Finance update

Revenue for the period from continuing operations was US$1,204 million (Q3 2012: US$1,110 million). The 9% increase in revenue is principally attributable to increased production and liftings from the Ebok field. In the nine months to 30 September 2013, the Group realised an average oil price from continuing operations of US$104.6/bbl (2012 US$108.8/bbl).

Gross profit for the period from continuing operations was US$574 million compared with US$574 million in the prior period. Unchanged gross profit compared to revenue growth of 9% reflects higher DD&A charges on oil and gas assets as a result of increased production, and higher royalty charges on Ebok.

Profit after tax from continuing activities was US$129 million (Q3 2012: US$123 million). The increase on the prior period reflects lower finance costs charged to the income statement, partially offset by the impairment of the Group's joint venture interest in JDZ prior to the expected withdrawal of participation from the licence.

During the quarter, the Group completed the disposal of its interest in the CI -11 block and Lion Gas Plant in Côte d'Ivoire. A provisional profit on disposal of US$25 million was recognised in the period, which remains subject to finalisation of working capital adjustments.

Operating cash flow before movements in working capital was US$860 million in the nine months to 30 September 2013 (Q3 2012: US$800 million). After movements in working capital, including tax payments of US$56 million, net cash generated by operating activities was US$880 million (Q3 2012: US$611 million).

During the nine months to 30 September 2013 the Group spent US$546 million developing its assets (comprising US$306 million investment in producing and development assets, US$240 million on exploration and evaluation projects). Additions to PP&E also includes a US$180 million investment to secure enhanced commercial terms on projects, as described in further detail below.

During 2013, Afren paid US$109 million for the acquisition of an additional 31% stake in FHN, bringing the Group's total equity interest to 78%.

Gross debt at 30 September 2013 was US$1,071 million, excluding finance leases. Cash at bank at 30 September 2013 was US$458 million, resulting in net debt (excluding finance leases) of US$613 million (31 December 2012: cash of US$599 million; net debt of US$561 million. 30 September 2012: cash of US$515 million; net debt of US$680 million). During the third quarter, the Group repaid its US$50 million unsecured facility, and redeemed convertible loan notes for US$63 million.

Post period end, we have made progress determining our tax liabilities and basis of taxation in Nigeria. We now expect to benefit from a significant improvement in terms for Ebok covering historical liabilities and liabilities arising through to mid-2016. The benefit of this is expected to be recognized in our year end results and we are currently quantifying the impact. The current and deferred tax liabilities recognized in the Group financial statements at 30 September 2013 relating to Ebok were US$254 million and US$393 million respectively.

In addition, as part of a wider agreement with our partners, Afren has secured additional benefits in the period from 2016 to 2021, including Afren having sole right to use capital allowances arising from the commencement of the project up to 2015.

Condensed consolidated statement of comprehensive income

Nine months ended 30 September 2013

Condensed consolidated balance sheet

As at 30 September 2013

Condensed consolidated cash flow statement

Nine months ended 30 September 2013

Condensed consolidated statement of changes in equity

Nine months ended 30 September 2013

Notes to the condensed consolidated financial statements

Nine months ended 30 September 2013

1. Basis of accounting and presentation of financial information

The condensed Group interim financial statements, comprised of Afren plc (''Afren'') and its subsidiaries (together, ''the Group''), have been prepared in accordance with the same accounting policies as applied in the audited financial statements for the year ended 31 December 2012, with the exception of the changes noted below. The Group policies are in accordance with International Financial Reporting Standards ("IFRS"). Certain information and note disclosures normally included in annual financial statements prepared in accordance with IFRS, as issued by the IASB, have been omitted or condensed as is normal practice for interim reporting periods. The condensed Group interim financial statements are unaudited, and do 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 were published and copies of which have been delivered to Companies House. The report of the auditors on those accounts was unqualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying the report, and did not contain any statement under sections 498(2) or (3) of the Companies Act 2006.

Changes in accounting policy

With the exception of the early adoption of IFRS 10, IFRS 11, IFRS 12, IAS 27 (revised), IAS 28 (revised) and the adoption of IFRS 13, the same accounting policies, presentation and methods of computation have been followed in these condensed Group interim financial statements as were applied in the preparation of the Group's financial statements for the year ended 31 December 2012. These interim financial statements should be read in conjunction with the Group's consolidated financial statements for the year ended 31 December 2012. Details of the changes in accounting policies arising from the adoption of IFRS 10 and IFRS 11 are discussed below. IFRS 12 relates to the disclosure of interests in other entities, and IFRS 13 establishes a single framework for measuring fair value, replacing guidance previously included in other standards. Neither IFRS 12 nor IFRS 13 has had a significant impact on the financial statements of the Group.

IFRS 10 Consolidated Financial Statements and IAS 27 Separate Financial Statements

IFRS 10 replaces the parts of the previously existing IAS 27 which dealt with consolidated financial statements. As a result of adopting IFRS 10, the Group has changed its accounting policy for determining whether it consolidates its investees. IFRS 10 requires consideration of whether the Group has power over an investee, exposure or rights to variable returns from its involvement with the investee and ability to use its power to affect those returns. In particular, IFRS 10 explicitly requires that the Group consolidates investees on the basis of de facto circumstances that give it power over the investee irrespective of the Group's shareholding. Under previous accounting standards the Group's accounting policy determined consolidation of investees primarily on the basis of its legal shareholding.

In accordance with the transitional provisions of IFRS 10, the Group reassessed the consolidation conclusion for its investees at 1 January 2013. As a consequence, the Group has changed its conclusion in respect of its investment in FHN, which was previously accounted for as an associate using the equity method. Although prior to May 2013 the Group owned less than half of the voting rights of the investee, the Directors have determined that under IFRS 10 the Group has had the power to direct the relevant activities of the investee. This is because the Group has held more voting rights of FHN than other vote holders and the Group had the ability to cast the majority of votes at shareholder meetings due to non-attendance by some shareholders. Accordingly, the Group has applied acquisition accounting to its original investment at 21 October 2010 as if the investee had been consolidated from that date.

Following the conclusion that FHN should be consolidated from 21 October 2010, Afren applied the transitional requirements of IFRS10, and restated the balance sheet as at 1 January 2012. These condensed financial statements present restated comparative periods to include the consolidation of FHN as a subsidiary. The effects of the change in accounting policy on the restated periods are presented in note 11.

1. Basis of accounting and presentation of financial information continued

IFRS 11 Joint Arrangements

As a result of adopting IFRS 11, the Group has changed its accounting policy for its interests in joint ventures. Entities over which the Group exercises joint control are now accounted for using the equity method, whereas they were previously proportionately consolidated. The Group has applied IFRS 11 retrospectively, in accordance with the transitional provisions, therefore 2012 results have been restated accordingly. On transition, the Group has collapsed the proportionally consolidated net asset value into a single investment. This change was not material. The effects of the change in accounting policy on the restated periods are presented in note 11.

Going concern

The directors are satisfied that the Group has sufficient resources to continue in operation for the foreseeable future, a period of not less than 12 months from the date of this report. Accordingly, they continue to adopt the going concern basis in preparing the condensed financial statements.

2. Finance costs and finance income

3. Earnings per share

4. 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.

5. Taxation

6. Operating segments

For management purposes, the Group currently 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 Kurdistan Region of Iraq. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group. Assets in Côte d'Ivoire, which were sold during the period (Note 10) are included in the Nigeria and other West Africa segment for management purposes but have been deducted in a separate column in the comparative segmental analysis below to enable reconciliation to the income statement. These assets are disclosed as discontinued operations in the income statement.

6. Operating segments continued

6. Operating segments continued

7. Borrowings

Ebok facility

On 22 March 2013, Afren signed a new US$300 million Ebok facility which has a three-year term and bears interest at Libor plus 4.0-4.8%. The new facility replaces the previous facility of approximately US$185 million. The new extended facility will be used to fund on-going capital expenditure and general corporate requirements including Group loans.

During the period FHN 113, a subsidiary of Afren, utilised a US$34 million facility for the acquisition of a 9% interest in the OML 113 licence. The facility bears interest at Libor plus 9% and has a two-year term.

The SOCAR loan of US$50 million was repaid on 5 July 2013 in accordance with the agreement.

On 5 July 2013 the Group redeemed convertible loan notes issued by FHN in 2011. US$50m of senior unsecured unsubordinated convertible notes were issued by FHN in September 2011 to fund ongoing development activities. The loan notes could have been converted to shares in FHN at any time from the date of issue until maturity (2017) in minimum tranches of US$5 million, at a conversion price of US$1.85 per share, which equated to approximately 27 million FHN shares. If not previously repaid or redeemed, the notes would be redeemed by FHN at maturity at a premium of 200 per cent. of the par value of the notes. The notes were redeemed for US$62.5 million resulting in an accounting gain of US$0.3m, which is included in finance income.

8. Other financial liabilities

Other financial liabilities represent a put option over FHN shares and deferred consideration in respect of the acquisition of FHN shares.

The option entitles the holder to require Afren to purchase 18,299,992 FHN shares at a price of $3.32, if exercised between 5 July 2015 and 5 January 2016. The liability is initially recognised at the present value of the redemption amount, and subsequently at amortised cost. On initial recognition the present value is charged to equity.

As announced on 5 July 2013, Afren purchased 33,966,333 FHN shares for a total consideration of US$105.4 million. Of this total, US$22 million is deferred for one year, and US$22 million deferred until the second anniversary of the transaction. Other financial liabilities include the present value of the non-current deferred consideration of US$21 million.

9. Share of joint venture

During the period, the Group recognised a loss from its share in joint ventures of US$25.8 million. The loss comprises the write-off of the Group's interest in joint ventures of US$8.4 million and impairment of amounts receivable from the joint venture of US$17.4 million. This predominantly relates to the impairment of exploration and evaluation assets in respect of JDZ Block 1. It is anticipated that the Group's participation in the licence will be withdrawn in the final quarter of 2013, and therefore the associated costs have been impaired.

10. Discontinued operations

On 16 May 2013, the Group entered into a sale agreement to dispose of Afren Côte d'Ivoire Limited and Lion GPL SA, which held Afren's interest in the CI-11 block and Lion Gas Plant respectively. The disposal was completed on 31 August 2013, on which date control of these two entities passed to the acquirer.

A provisional profit on disposal of US$25.3m has been recognised in the period. This remains subject to finalisation on agreement of working capital adjustments.

11. Effect of change in accounting policies

As discussed in note 1, the financial performance and position of the Group has been restated for the nine months ended 30 September 2012 and 31 December 2012 to reflect the adoption of IFRS 10 and IFRS 11. The quantitative impact on the 30 September 2012 financial statements of adopting these standards is set out in the following tables. The effect on the 31 December 2012 financial statements was presented in note 14 of the Group's 2013 Half-Yearly Report, which is available at www.afren.com. The adoption of IFRS 10 has resulted in the consolidation of FHN as a subsidiary in all comparative periods restated. The adoption of IFRS 11 has had an effect on the accounting for Afren's two joint ventures held through Afren Global Energy Resources Limited and Dangote Energy Equity Resources Limited.