AFR.L Regulatory News (AFR)

Afren plc 

2014 Full Year Results

30 April 2015 - The Board of Afren plc ("Afren" or "the Group") announces its results for theyear ended 31 December 2014

· Net production excluding Barda Rash of 31,819 bopd, slightly below the full year guidance range of between 32,000 - 36,000 bopd. Year-on-year reduction of 32% due to cost recovery at Ebok and delays with bringing new wells on stream across producing asset base in Nigeria

· Financial results impacted by material impairment charge of US$1.1 billion due to the fall in oil prices and curtailment of capital expenditure and US$0.9 billion in respect of the write-off of Barda Rash reserves

· Reserves replacement ratio significantly impacted due to write-off of 2P reserves at Barda Rash

· 2015 capital allocation to be prioritised to existing producing asset base in Nigeria. Forward programme optimised for a lower oil price environment. Production guidance expected to be 23,000 - 32,000 bopd reflecting lower production from Ebok following the end of all cost recovery

· Wide-ranging portfolio review underway, targeting selective divestments and farm-outs in 2015

· Broad programme of cost reductions and operational measures targeted expected to lead to efficiencies and significant cost savings in 2015

· Unauthorised payments issue discovered in July 2014 which led to the dismissal of former CEO, former COO and two associate directors

· Lower oil prices significantly impacted the business at the start of 2015 resulting in a review of the Company's capital structure, liquidity, funding requirements and business plan

· Holders of existing notes have provided interim funding of US$200 million by way of new Private Placement Notes. Proceeds to be used for general corporate purposes and capital expenditure. Wider recapitalisation programme expected to be completed by the end of July 2015 providing a further US$55 million to US$105 million in net cash proceeds

Afren had an extremely challenging year in 2014. Following the unauthorised payments issue discovered in July, the Board initially suspended and then dismissed the former CEO, Osman Shahenshah, and former COO, Shahid Ullah, as well as two Associate Directors, Iain Wright and Galib Virani. Their actions significantly affected the confidence of all our stakeholders.

Operationally, Afren also encountered a number of headwinds in 2014. Operational delays impacted the timing of the production ramp-up across our producing asset base which, when combined with the rapid deterioration in the oil price environment during the second half of the year, meant that our financial performance fell well below our expectations.

The impact of the lower oil prices resulted in an impairment charge of US$273 million in respect of the carrying value of our production and development assets. In addition, as a result of the liquidity constraints of the business, future capital expenditure on our exploration and evaluation (E&E) assets has been curtailed and has led to an additional impairment charge of US$839 million. Despite this, the Group believes that upside potential remains in respect of the E&E portfolio and is optimistic of making recoveries on some of the assets that have been fully impaired through either development or sale.

Following an updated reserves report from RPS Energy, an impairment charge of US$933 million was recognised in respect of the Barda Rash PSC. This reflected the operational and technical challenges that were encountered in drilling a field which proved to be markedly different to our initial assessment and the approved Field Development Plan (FDP).

The decline in production and revenue, associated with unprecedented impairments, resulted in a loss before tax from continuing operations for the year ended 31 December 2014 of US$1,955 million. While the Group's cash position was US$237 million as at 31 December 2014, its liquidity was further impacted as a result of restricted and segregated cash balances in place to address operational requirements. These results, together with the strains of operating in a significantly lower oil price environment, severely impacted our business at the start of 2015 and led to wide ranging refinancing proposals being discussed with our lenders and advisors as well as third parties. Following such review, the Company concluded that a transaction with its current creditors offered the best alternative that was capable of being implemented. These were agreed in principle and announced on 13 March 2015, after the Company had deferred certain amortisation and interest payments due under its secured Ebok facility and 2016 Senior Notes. The Company has successfully raised US$200 million in interim funding and further deferred a US$50 million amortisation payment. This interim funding is expected to be refinanced by a broader financial and capital restructuring to be implemented in the early part of H2 2015. The objective of this restructuring, which is intended to raise a further US$55 million to US$105 million in net cash proceeds, is to recapitalise the business, extend the maturity of our debt, lower our cost base and focus the Company's operational efforts towards achieving production and cash flow increases from our existing Nigerian production base, as outlined in our business plan. These measures should enable Afren to benefit favourably from any potential upward re-rating in the oil price dynamics but at the same time ensure the business can return to profitability from a lower oil price base.

We continue to see value in our portfolio and are confident that we can emerge from the difficulties of the past nine months as a more nimble, well governed and transparent business.

Cultivating the right culture

As part of the evolution of an entrepreneurial business that witnessed rapid growth in a relatively short space of time, it is fair to say that while we had the right systems and processes in place, there were a number of issues with the culture at the top of our organisation that rendered the day-to-day implementation of these ineffective.

On 31 July 2014, Afren announced that during the course of an independent review on the Board's behalf by Willkie Farr & Gallagher (UK) LLP (WFG) of the potential need for disclosure to the market of certain previous transactions, evidence was identified in respect of the receipt of unauthorised payments amounting to US$45 million for the benefit of the former CEO (Osman Shahenshah), former COO (Shahid Ullah) and other selected employees and third parties associated with the Ebok project. This led initially to the suspension of these two individuals and the appointment of Egbert Imomoh to Executive Chairman (previously Non-Executive Chairman) and Toby Hayward as Interim CEO (previously Senior Independent Director). On 13 October 2014, following the completion of this review by WFG, the Board decided to terminate the employment and directorships of the former CEO and COO with immediate effect on the grounds of gross misconduct. Furthermore, the Board also decided to terminate the employment of the two Associate Directors (Iain Wright and Galib Virani), who received payments in breach of the Company's approved remuneration policy.

In connection with the initial review, WFG also concluded that the Company failed to comply with the reporting obligations under the Listing Rules in respect of two of the three transactions investigated. Afren has notified the Financial Conduct Authority (FCA) in respect of these breaches and continues to cooperate with them fully. Furthermore, as part of their review and at the request of Afren, WFG engaged KPMG LLP (KPMG) to undertake an independent review of the accounting for the three transactions investigated. Following the completion of the final report on 28 October 2014, Management have reassessed certain accounting judgements made in the prior year and have concluded it is appropriate to restate the financial statements at 31 December 2013. As previously re-iterated, these have not had any impact to the net assets or profit after tax (see note 12 of attached financial statements). The payment of US$45 million in unauthorised payments was made by a third party and has had no impact on Afren's financial statements.

On 31 December 2014, Afren announced that it had secured an agreement to a cash settlement of US$17.1 million in relation to the unauthorised payments from Mr Shahenshah and Mr Ullah and a further US$3.0 million towards certain investigation and legal costs. Further sums have been received from certain other individuals and steps are being taken to secure the return of remaining amounts. With the exception of those amounts relating to certain investigation and legal costs, these funds will be returned to Oriental Energy Resources Limited (Oriental).

In connection with its review of the previous transactions, WFG made certain recommendations as to how the Company could improve and strengthen its internal controls. As part of the Company's implementation of improved internal compliance procedures, the Company engaged WFG and also KPMG to assist it with its review of certain elements of its compliance with such procedures. In connection with this review, on 20 March 2015, Afren announced that it had reported to the committee of the bondholders (who are subject to the ongoing discussions around interim funding) preliminary concerns regarding the hire of an individual within its operations in 2012 and the payment of certain travel and accommodation expenses connected to Afren's activities. WFG has undertaken a substantial review of such matters, which is still ongoing but which is almost complete save for some follow-up in relation to these two issues. As disclosed in note 10 to the financial statements having received the preliminary findings from the WFG review, the Company has also notified the Serious Fraud Office (SFO) and has taken steps to halt its previous practices in relation to such expense payments.

The findings from WFG have clearly demonstrated a need to strengthen our corporate culture, organisation and accountabilities. Following an internal review during 2014, and prior to the discovery of the unauthorised payments, we undertook a project to completely re-design the Company's Code of Business Conduct and to train all employees and contractors on its requirements. This exercise was extended following the discovery of the unauthorised payments, to include a more detailed training exercise which was completed by all staff by the end of the year.

The new Code contains 15 commitments which govern the activities of staff members and contractors. They embrace all aspects of the organisation's business. They address bribery, gifts and entertainment, conflicts of interest, sanctions, use of company information technology, use of company physical assets, personal information, business information, environment and climate change, health and safety, communities, human rights, inclusive workplace behaviour, working with others and dealing in company securities. Each commitments section contains guidance on the Group's approach. The Code also explains how the Group addresses corporate responsibility matters and contains advice on what personnel should do if they are aware of Code breaches. This information also highlights the Group's confidential whistle-blowing hotline which is run by Safecall, a specialist provider, together with information on when and how to use it.

We are confident that the new Code and the associated training procedures, which reflect industry best practice, will help instil at every level of the organisation a culture that champions and promotes the values of honesty, transparency, openness and trust.

Risk management review

Our risk management programme has continued to evolve throughout 2014. In particular we have carried out a detailed anti-bribery and corruption risk assessment and have reviewed the potential business risks associated with climate change. These reviews resulted in the adoption and publication of our revised Code of Business Conduct as outlined above and a new climate change strategy. In 2014 we also conducted an internal audit review of the business risk management function and have engaged KPMG as external consultants to assist management in addressing the findings of this review, and have outsourced the internal audit function to PwC. As a result we are currently refining the process of reviewing and reporting risks through the Audit and Risk Committee and up to the Board.

Navigating in uncertain times

In 2014, average gross and net production, excluding Barda Rash, was 47,560 and 31,819 bopd respectively, falling slightly below our full year net production guidance of between 32,000 to 36,000 bopd. Production was at the lower end of guidance, principally due to delays installing the Ebok CFB extension, the natural decline in production from existing wells and unplanned downtime at Ebok in September 2014. OML 26 production was affected by the Q1 2014 declaration of Force Majeure by Shell, operator at the Forcados Terminal. In Q1 2014 the Ogini-22 and Ogini-23 wells were successfully spudded, drilled and completed while a third producer was spudded in December 2014 and completed in February 2015. A fourth producer, Ogini-25, was spudded in February 2015 and completed in March 2015 with drilling of a fifth producer in progress. Elsewhere, at the Okoro field, production during the period was in line with expectations, incorporating downtime earlier in the year.

On an annualised basis, Group net production in 2014 was down 32% due to cost recovery of the initial development costs at Ebok and delays in achieving production ramp-up at Ebok, OML 26 and from the Barda Rash field, Kurdistan region of Iraq. Revenue for the full year in 2014 was US$946 million (31 December 2013: US$1,644 million), reflecting both lower production volumes and the impact of lower realised oil prices during the second half of the year (1H 2014: US$108/bbl, 2H 2014: US$86/bbl). Net debt at the end of 2014 was US$1,067 million (31 December 2013: US$739 million), which included cash at bank of US$237 million (31 December 2013: US$390 million). Year-end cash at bank included US$80 million in respect of the remaining hedges of 2.85 mbbls to 31 July 2015 which Afren sold in December. Capital expenditure for the period was US$769 million, with US$625 million allocated to production and development activities and US$144 million allocated to E&E work.

On 12 January 2015, Afren outlined its intention to review its strategic options in Kurdistan, including the potential divestment of Barda Rash, reflecting both disappointing operational results at the field and a significant reserves and resources downgrade following an updated Competent Person's Report (CPR) by RPS Energy. The movement in reserves at Barda Rash has resulted in a material impairment charge in the year of US$933 million. In addition, an impairment charge of US$273 million has been recognised as a result of a review of the carrying value of our PP&E assets at lower commodity prices and a further US$115 million of goodwill has been written off. Exploration write-offs in the period were US$839 million. Despite this, the Group believes that significant upside potential remains in respect of the exploration and evaluation portfolio and is optimistic of making recoveries on some of the assets that have been fully impaired through either development or sale. Our reserves replacement ratio, defined as the ratio of the number of barrels of oil equivalent discovered compared with the number produced over a three-year period, fell significantly from 580% to 9%. This was principally due to the elimination of 2P reserves at Barda Rash and due to limited E&E success in 2014. We did achieve a small net 2P increase in the year of approximately 4 mmbbls in respect of our offshore Nigerian licence, OML 113, following the publication of an updated CPR from AGR TRACS International Ltd.

Driving shared responsibility

At the beginning of the year we developed an over-arching corporate responsibility strategy that was reviewed and approved by the Board of Directors in March 2014. This strategy document formed the basis for setting the 2014 corporate responsibility targets. Despite challenging operating conditions we met our corporate responsibility stretch target for 2014, making significant progress across a wide range of key issues. In particular, we achieved a 30% reduction in both our Lost Time and Total Recordable frequency rates across the business.

Strengthening our capital base

Our financial results in 2014, as well as the sharp decline in market oil prices in the second half of 2014, placed very significant pressure on the Group's liquidity position. With revenue for 2014 of US$946 million, down 42% year-on-year, and extraordinary impairments to property, plant and equipment (US$1,206 million), intangible exploration and evaluation assets (US$839 million) and goodwill (US$115 million), the Group recorded a loss before tax from continuing operations for the year ended 31 December 2014 of US$1,955 million. As a result, the Group had net current liabilities of US$459 million as at 31 December 2014. While the Group's cash position was US$237 million as at 31 December 2014, its liquidity was impacted as a result of restricted and segregated cash balances in place to address operational requirements.

The Company's near term cash flow was also impacted by capital expenditure incurred in late 2014 before operational changes had been implemented to adapt to the current lower oil price environment, as well as an inability to continue with the planned refinancing in the middle of 2014 due to the suspension of its former CEO and COO at such time. As a result, the Directors commenced an urgent review of the Group's capital structure, liquidity and funding requirements. In connection with new costs optimisation measures to improve its liquidity position, the Board engaged Alvarez & Marsal to provide services as Chief Restructuring Officer.

In light of the Group's liquidity position, the Company obtained from the lenders of the US$300 million Ebok debt facility a deferral of the US$50 million amortisation payment due on 31 January 2015. On 4 March 2015, the Group announced that the Board had decided at the expiration of a 30 day grace period not to pay US$15 million of interest which was due on 1 February 2015 under its 2016 Senior Notes. The Board is also currently taking advantage of a 30 day grace period not to pay US$12.8 million of interest which was due on 8 April 2015 under its 2019 Senior Notes. As at 30 April 2015 Afren is in default under the terms of its 2016 Notes due to the non-payment of interest and will be in default under the terms of its 2019 Notes on 8 May 2015. The Company has received assurances from the ad hoc committee of noteholders under its 2016 Notes, 2019 Notes and 2020 Notes (Existing Notes) (which members hold in aggregate approximately 50% of the total principal face amount of the Existing Notes) (Ad Hoc Committee) that the Ad Hoc Committee has no current intention to take enforcement action with respect to the 2016 Notes or 2019 Notes held by its members as a result of the failure to make payment of interest due under the 2016 Notes or 2019 Notes, on the basis that agreement has been reached with the Company and its key stakeholders on the terms of a consensual (but conditional) restructuring.

On 13 March 2015, the Group announced a preliminary agreement for the receipt of interim funding and the recapitalisation of the business. The agreement entered into by Afren together with certain noteholders under its Existing Notes and a majority of the lenders under the Group's existing US$300 million Ebok credit facility, is intended to ultimately result in the provision of US$255-305 million of net total funding before the end of July 2015 (Recapitalisation). On 30 April 2015, in respect of the interim funding, the Company entered into definitive agreements with certain Noteholders and issued US$212 million of private placement notes (PPN), providing US$200 million in net cash to the Group. In conjunction with such agreement, the lenders under the Group's existing US$300 million Ebok credit facility agreed to the deferral of the US$50 million amortisation payments due on 31 January 2015 and 30 April 2015 until the completion of the implementation of the Recapitalisation (at which point it is expected that the amortisation payments will be further deferred until after the repayment of the New High Yield Notes). The PPN will be repayable by April 2016 if not refinanced through the Recapitalisation.

In connection with the Recapitalisation, on 30 April 2015 the Group entered into a conditional agreement to raise US$55 million in additional net proceeds (after the repayment of the PPN) from the issuance of new High Yield Notes due in 2017 (New HY Notes). This amount may be increased to up to US$105 million in total additional net proceeds. This would provide the net total funding of US$255 - US$305 million. In addition, as part of the Recapitalisation (i) 25% of the Existing Notes will be converted to new equity in the Company; (ii) the remaining 75% of the Existing Notes will be extended to mature as to US$350 million in each of December 2019 and December 2020; (iii) the existing Ebok credit facility will be extended to 2019; (iv) new shares will be issued to subscribers to the New HY Notes and the PPN; and (v) the Company will undertake an equity offering of up to US$75 million to shareholders. The Group has also reached agreement with the lender of its Okwok/OML113 facility to restructure and defer this facility until 2018. This Recapitalisation will result in very substantial dilution for our existing shareholders, which reflects the underlying financial position of the Group.

In order for the Recapitalisation to be implemented there are other conditions that need to be fulfilled, including obtaining (i) the approval of requisite majorities of holders of the Existing Notes in connection with a scheme of arrangement of such Existing Notes; (ii) approval from the relevant courts in the UK and the US as to such scheme of arrangement; and (iii) agreement from the Group's remaining lenders. The Company will also seek the approval of shareholders in general meeting to the terms of the Recapitalisation, which is required in order to issue the new ordinary shares in connection with the Recapitalisation. If shareholder approval is not received, the Recapitalisation will still proceed, but on amended terms for the New HY Notes.

There is a risk that one or more of these steps may not be completed or satisfied and the Recapitalisation may not occur. If additional funds are not available to be drawn under the New HY Notes, and the Recapitalisation does not proceed, the Directors are of the opinion that the Group would become insolvent, absent an alternative proposal being received by the Company that is capable of being implemented.

If shareholder approval of the Recapitalisation is not received, the Ad Hoc Committee and the lenders under the Group's existing US$300 million Ebok credit facility have agreed to an alternative restructuring plan, whereby the economic terms of the New HY Notes will be amended, and the amendment and restatement of the Existing Notes will be revised (so that no new shares are issued). In addition, the New HY Notes will include a requirement for the Company to initiate a sale of the Group's business by the end of 2016, which together will mean that existing shareholders would be unlikely to see any return on their current investment.

On the basis that the recapitalisation is successfully achieved as outlined above, the Group's financial footing and ability to continue in operation would be significantly strengthened.

Building for the future

Looking ahead, Afren expects full year 2015 net production to average between 23,000 - 32,000 bopd, with a forecast capital spend of approximately US$0.4 billion, allocated principally to our existing high-margin Nigerian producing assets. Our forward guidance for 2015 reflects the impact of operating in a significantly lower oil price environment and the outcome of refinancing proposals currently underway. We have also agreed with our Partner, Oriental, that they will fund their share of capex at Ebok. Going forward this will result in a lower share of production following the end of all cost recovery. In respect of our exploration and evaluation commitments this year, Afren will continue to engage with host governments and Partners to manage commitments in a low oil price environment and discuss opportunities for strategic divestments.

Our revised business plan assumes a lower oil price environment for the foreseeable future and is expected to lead to year-on-year growth in the underlying net production base through to 2017. In addition, in line with our peers, the Group is in the process of implementing a streamlining programme alongside a number of operational measures that are expected to lead to material cost savings.

During what has been a very difficult year for all our stakeholders, we would like to extend our gratitude to our employees and contractors who have demonstrated their unwavering commitment, professionalism and loyalty to steering our business towardsa brighter, more prosperous future. We still have significant challenges facing the Company but we are confident that the measures we are implementing will, in time, deliver the exciting potential within our portfolio.

Board changes

Following the conclusion of the investigation into the unauthorised payments, which led to the dismissal of the former CEO, Osman Shahenshah, and former COO, Shahid Ullah, we commenced the search for a new CEO in October. We are pleased to announce the appointment of Alan Linn as the new CEO for the Afren Group. He has 35 years of international experience in the oil and gas industry and brings with him a wealth of knowledge in restructuring businesses in challenging environments. In addition, the Board will be further strengthened with the appointment of new directors to broaden its expertise and an executive search firm is being retained to assist in this process; announcements will be made in due course in respect of this. Toby Hayward has stepped down from his role as interim CEO and will resume as a non-executive director.

In 2014, we strengthened the Board with the appointment of Iain McLaren. Mr McLaren, who now chairs the Audit and Risk Committee and Remuneration Committee, brings extensive financial accounting and capital markets experience, having held senior leadership positions in both the finance and energy sectors. His experience will be particularly valuable as Afren embarks on a period of change. During the year, Mr Ennio Sganzerla resigned as Non-Executive Director of Afren in order to pursue other business interests.

We would like to reassure all our stakeholders that the Board fully recognises the need to rebuild a stronger Board and executive team as quickly as possible, both to restore confidence and to take Afren forward to meet the opportunities that remain across its portfolio. 

Our operations: Nigeria, other West and South Africa

Nigeria currently contributes all of Afren's production. 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. Total gross production at the Okoro field in 2014 was 6 mmbbls of oil, representing a gross average daily rate of 16,451 bopd, and a process uptime of over 97%. The year-on-year decrease of circa 9% was in line with expectation, incorporating planned downtime associated with the riser re-termination work carried out in Q1 2014.

Since the start of production in 2008, the Okoro field has continued to perform ahead of expectations, delivering aggregate gross production volumes to the end of December 2014 of c.39.4 mmbbls, significantly above the original 2P scenario of 26.2 mmbbls, a remarkable achievement for our first greenfield development project.

During the year, in order to optimise production at the Okoro main field, the Adriatic 1 rig was moved to the Okoro Main Well Head Platform (WHP) where one producer, Okoro-15, and one side track, Okoro-12 ST1, were brought on stream and are currently producing at rates of approximately 2,000 bopd in line with expectations. In Q3 2014, the Partners sanctioned the Final Investment Decision (FID) for the Okoro Further Field Development (Okoro FFD).

The rig for the Mobile Offshore Platform Unit (MOPU) was procured and arrived in the construction yard in Singapore inQ4 2014. In February 2015, Amni and Afren began discussions on how best to manage the Okoro FFD in light of deteriorating oil prices with a view to re-engineering the forward work programme at Okoro.

Outlook

The re-engineered Okoro FFD may utilise the existing infrastructure at the field, and will incorporate the development of the Okoro FFD discovery over two phases from the Okoro Main WHP. The forward drilling schedule will enable production decline from the main field to be offset with new wells coming on stream from the Okoro FFD.

Continued strong production performance at the Ebok field

In 2014, the Ebok field produced 10.1 mmbbls of oil, representing a gross average daily rate of 27,767 bopd and a process uptime of over 97%.

The year-on-year fall in gross production at Ebok was principally due to the lack of new production from the delayed Central Fault Block (CFB) extension, which was planned to offset the natural decline from existing wells. During the year Afren and its Partner, Oriental, successfully concluded the drilling campaign from the North Fault Block (NFB) by bringing three additional wells on stream - two injectors and one producer, delivering on average 7,000 bopd. While these new wells were unable to make up for the lack of CFB production, they did help the Partners reach an exit rate for 2014 at 32,123 bopd.

2015 outlook

In 2015, the Partners intend to undertake further field development at Ebok, finalising the CFB extension platform and West Fault Block upgrades and debottlenecking. Having completed the installation of the CFB extension wellhead jacket in late Q4 2014, the Partners completed the top-side installation of the bridge and decks in March 2015 and are targeting hook-up and commissioning of the facilities by mid Q3 2015. The Central Fault Block extension platform is a 12-slot (24-well) wellhead platform designed to support 15 wells initially (10 production and five injectors), additional slots for future wells, power generation and space for installation of an additional gas compressor.

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.

Field Development Plan approved

In January 2014, the Partners received approval for the FDP for Okwok from the Nigerian authorities. Consequently, Okwok was reclassified as a Development asset, a strong endorsement of the successful appraisal work undertaken by the Partners since its 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 FSO located approximately 13km to the west.

During 2014, the Partners successfully completed the fabrication and installation of the wellhead jacket.

2015 outlook

Afren, together with its joint venture partners Oriental and Addax Petroleum, have completed and flow tested their first development well, Okwok 13. The well was drilled and completed in April 2015 from the Okwok jacket, which had been previously installed in Q4 2014. Drilled to a total measured depth of 9,212ft, the well completed in the LD-1B Lower reservoir in over 1500ft of horizontal section and was successfully flow tested at a rate of 5,400 bopd (24.5 deg API oil) on a 36/64" choke with a producing GOR of 355scf/bbl and a flowing wellhead pressure of 1,248psi. The well has been suspended in readiness for the planned installation of a Mobile Offshore Production Unit and the Okwok crude oil sales export pipeline.

Following the completion of the well and in light of the current low oil prices, Afren and its Partner, Oriental, are currently reviewing the optimal development plan for Okwok.

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 exploration drilling and 2015 outlook

Following the completion of Ocean Bottom Cable 3D Seismic over the whole Ebok/Okwok/OML 115 area, Afren and its Partner, Oriental, spudded the Ameena East prospect in November 2014 using the Shelf Adriatic 1 drilling rig. The prospect was targeting 65 mmbbls of gross unrisked resources in zones in the Biafra/Isongo intervals that are productive north of the acreage, with secondary objectives in the shallower Qua Iboe reservoirs.

The Ameena-2 well was drilled to the planned total depth of 8,200 ft. Although the secondary Qua Iboe reservoirs were found to be water-bearing in the shallow portion of the hole, light hydrocarbons were encountered in a net interval of 38 ft with an average porosity of 16%, as indicated by wireline logs. No further testing was undertaken. The well has been temporarily abandoned and made available for potential re-entry at a future time.

Overview

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

During the year, gross average production from the Ogini and Isoko fields was 3,342 bopd. In June 2014, Partners received approval from the Department of Petroleum Resources (DPR) for the initial phase of the Ogini FDP, comprising five wells out of the 37 redevelopment wells proposed in the FDP. Following this, the Partners successfully spudded, drilled and completed two of these initial five new wells, Ogini-22 and Ogini-23, during the second half of the year. The third producer, Ogini-24, was spudded in December 2014 and completed in February 2015 and the fourth, Ogini-25 completed, in March 2015. Drilling on the fifth producer, Ogini-26, is currently in progress. All five wells are being drilled from the same location cluster. The full production potential of the completed wells is yet to be fully realised due to the fact that gaslifting cannot be introduced due to safety reasons associated with gas operations while the rig is still on location. Two of the wells tested in excess of 2,000 bopd and a third about 1,000 bopd during post completion well tests without the gaslift.

2015 Outlook

The Partners expect to drill and complete the remaining of the initial five approved wells during H1 2015. Results and data obtained from these wells will be incorporated into field-wide data to facilitate an update of the existing FDP and enable the asset to seek approvals for further wells to be drilled. Submission of the OML 26 field development plan to Nigerian authorities for Isoko is expected in the second quarter of 2015.

The LACT unit at the Eriemu pigging manifold has undergone the Site Acceptance Test (SAT) and has been duly commissioned. Estimated volumes delivered to the Forcados Oil Terminal (FOT) during 2013 and 2014 prior to SAT and commissioning of the LACT unit are subject to reconciliation and agreement with Shell.

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. A well was drilled as a straight line hole in August 2013 followed by a side track to access the syn-rift.

3D Seismic acquisition and 2015 outlook

Following the Ogo discovery in 2014, the 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 existing coverage on the two licences. Processing of 3D seismic data is ongoing. The fast track post-stack time migration was delivered in August 2014 and the final production pre-stack time migration was delivered in late Q4 2014. The pre-stack depth migration is due in H1 2015. The interpretation of these data sets will be used to finalise a well location. Various funding options are being investigated for appraisal drilling. Post period end, Afren has instructed NSAI to commence the preparation of a Competent Person's Report for OPL 310 incorporating the new block wide seismic data, once the processing has been completed.

Overview

OML 113 is located 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 mean contingent resources to be 179 mmboe, principally related to the Aje field, with an additional 205 mmboe of mean prospective resources on the block.

FDP approved, FID sanctioned and 2015 outlook

In January 2014, JV Partners submitted the FDP for the Aje field to the Nigerian DPR. The FDP was approved in March 2014 andis 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 close to the Aje-2 subsurface location. The FDP envisages first oil commencing in late 2015 with mid-case reserves of 32.4 mmbbls.

On 7 October 2014, the JV Partners on OML 113 sanctioned the FID for the first phase of the Cenomanian development in the Aje field that will include two subsea production wells tied back to a leased FPSO.

Afren has completed an extensive 2,716 km² 3D seismic across OPL 310 and OPL 113 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.

In respect of our commitments this year, Afren will continue to review its work programme in light of its funding position and the impact of low oil prices, at the same time as seeking alignment with host governments and JV Partners on the timing of work programmes.

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

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

The agreement resulted in 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 CI-523 Block included 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 CI-525 Block included the legacy CI-505 Block and the northern portion of the legacy CI-01 Block, thereby extending our acreage to the north. The operator on the CI-523 Block is Taleveras Group whilst the operator on the CI-525 Block is 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 CI-523 and CI-525 blocks significantly increase Afren's existing exploration acreage and upside potential in the region.

2015 outlook

Afren completed a 1,896km2 3D seismic survey on CI-523 and CI-525 in Q4 2014. The data acquired will be processed in 2015.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with host governments on the timing of work programmes and potential opportunities for strategic divestments.

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.

2015 outlook

Following an economic evaluation in 2014, Afren fully impaired its holding in the Keta block (US$35.5 million).

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.

2015 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.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

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.

2015 outlook

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

A two-year licence renewal was granted on Block 2B by the regulatory authorities on 26 January 2015. The effective date of this two-year renewal period is 13 March 2015. The work programme over this period will involve geological modelling of the A-J graben sediments.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

Our operations: East Africa

Our portfolio of East African assets covers an extensive area of over 68,000 km2 located in basins of proved working hydrocarbon systems. We focus on onshore Karoo aged 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 our entry into the region, we have acquired extensive seismic data which has enhanced our understanding of the basins and resulted in a significant upgrade to our prospective net resource base from 1,233 mmboe to 3,275 mmboe of risked mean recoverable resources.

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 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 data set has also enhanced our view of the oil prospectivity in the south of this large frontier block. A large surface anticline in the east of the acreage is also considered highly prospective for oil and further seismic acquisition was planned for Q4 2014 in order to locate an exploration well on the feature.

2015 outlook

Seismic operations were suspended on Block 1 during December 2014 as a result of regional security issues. We continue to monitor the security issues closely and will only resume operations when it is safe and prudent to do so. Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

Overview

Blocks L17 and L18 are in the Lamu Coastal Basin, south-east Kenya, covering an area of approximately 4,881 km2. There is an onshore component and in the offshore water depths vary 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 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 is recorded within the Eocene section in the Pemba-5 well. There are oil seeps in the Lamu Basin and on Pemba Island linked to Eocene and Jurassic source rocks which imply 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. Oil and gas was discovered outboard of L18 by BG in Q1 2014 (the Sunbird-1 discovery).

In January 2012, Afren completed the acquisition of 1,207 km of 2D seismic data targeting the deeper water portion of the blocks. Interpretation of the data 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 net mean prospective resources on the blocks, to 668 mmboe. Afren completed the acquisition of 1,006 km2 of 3D seismic data during December 2012, in lieu of a well commitment, to better understand the deep water prospectivity. 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. The onshore seismic data highlighted an expansive shallow-water/onshore trend called the Mombasa High. An airborne gravity and magnetic survey was acquired over the Mombasa High structure in Q2 2014 to allow the optimal positioning of a 250 line km 2D seismic survey which commenced acquisition in Q4 2014.

2015 outlook

The 250 line kilometre onshore 2D seismic survey was completed in January 2015, the results of which will be used to locate targets for exploration drilling.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government on the timing of work programmes and potential opportunities for strategic divestments.

Overview

The Tanga Block is located offshore in 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 the southerly extension of the same coastal high and basin trough plays, allowing us to use our regional expertise and knowledge.

In July 2013, Afren initiated seismic interpretation of a 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. Further interpretation work has elevated the Nanasi prospect to the forefront of drilling opportunities in the deepwater of the Tanga block and work is ongoing to raise the shallow water prospects to ready-to-drill status. This will potentially involve the acquisition of a shallow water 3D seismic survey of around 400 km2.

2015 outlook

The Partners plan the acquisition of a shallow water 3D seismic survey of around 400 km2 subject to regulatory approval and availability of funding in 2015.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

Overview

Areas A and B are in the Seychelles micro-continent, in shallow to deep water in the northern half of the Seychelles plateauand 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 source rocks. The Karoo formation contains both a 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 licenceareas that are located in shallow to deep water in the northern half of the Seychelles plateau. A major new 2D survey inQ4 2011 (3,733 km) focused on these areas to better define their prospectivity.

In 2013, Afren completed a major 3D seismic programme, the first 3D surveys 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 has been completed. Early results have confirmed pre-3D prospectivity in the southern deep water portion of Area A.

2015 outlook

A 1,200 square kilometre 3D seismic survey is in the planning stage to cover shallow water leads in Area A.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

Overview

Block 1101 is on the eastern flank of the Ambilobe Basin, onshore northern Madagascar. The block encompasses anarea 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. 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.

Successful shallow borehole coring programme

In late Q4 2014, Afren completed a multi-location shallow borehole coring programme which included the re-drill ofa previously reported oil discovery. A total of four strategic locations on Block 1101, which measured around 11,200 km² (2.8 million acres), were successfully drilled and cored to an aggregate depth of 6,500 ft with approximately 5,720 ft of core samples recovered. Drilling at each of the locations successfully completed the respective technical objectives to assess specific aspects of the Block's petroleum systems.

Two core holes were drilled to depths of 2,112 ft and 1,625 ft adjacent to the 1902 coal borehole (Ankaramy-1) which had reportedly encountered "hydrocarbon shows". Cores recovered from both locations indicated the presence of hydrocarbonsand potentially good reservoir quality over multiple zones.

Early indications provide further evidence of at least three different source rocks working across the Block in the Triassic, Jurassic and Cretaceous.

2015 outlook

Further detailed analysis of the cores will be undertaken in Q2 2015 to confirm the nature and extent of the hydrocarbons.

Net risked mean prospective resources on the block are estimated at 205 mmboe.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

Overview

Block 8 is located in the Ogaden Basin covering an area of 11,062 km2. Exploration in Ethiopia began in the 1970s with Tenneco discovering the Calub and Hilal gas fields and 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. The El Kuran-3 well was spudded on 13 October 2013 using the Sakson 501 drilling rig and reached a total depth of 11,575 ft. Oil and gas was penetrated in several intervals and commerciality studies have commenced in order to assess the optimal way of developing these reservoirs. The Ethiopian ministry has granted the Joint Venture an 18 month period to carry out these studies.

2015 outlook

Studies will be completed on the optimal way of developing and exporting the oil and gas contained in the El Kuran discovery.

Due to the Group's liquidity constraints resulting in a curtailment of budgeted expenditure for this asset, despite Afren retaining its interest in the asset a full impairment was recognised at the end of 2014 in order to meet with the requirements of International Financial Reporting Standards.

In respect of our commitments this year, Afren will continue to review its work programme in the light of its funding position and the impact of low oil prices at the same time as seeking alignment with the host government and its Partner on the timing of work programmes and potential opportunities for strategic divestments.

Our operations: Kurdistan region of Iraq

Overview

The Barda Rash PSC is 55 km north-west of Erbil. 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.

Strategic options being evaluated

On 12 January 2015, Afren announced that an updated Competent Person's Report (CPR) of Barda Rash, carried outas part of the Company's annual reserves review, was expected to show a material reduction to previously published estimates of reserves and resources, essentially eliminating gross 2P reserves of 190 mmbbls and revising gross 2C resources from 1,243 mmbbls to around 250 mmbbls. The final RPS report confirmed the results of the announcement.

The decrease in 2P and 2C reserves and resources followed the 2014 reprocessing of 3D seismic shot in 2012 alongside results from the Company's drilling campaign. Overall, the reservoirs have not performed according to previous expectations of the Company, RPS and the approved FDP. The wells have produced higher water cuts than expected and the Company has encountered operational challenges associated with the drilling of difficult complex fractured reservoirs. Production from these reservoirs could potentially be achieved with the implementation of recovery schemes requiring significant capital expenditure, which may well be appropriate for a company with a different strategic focus. Furthermore, while recent results at the field have indicated the presence of light oil accumulations from the deeper Triassic Kurra Chine reservoirs, these have a high level of associated Hydrogen Sulfide (H2S), which would require significant capital expenditure to develop. In light of the above, the Company is in discussions with the MNR regarding potential divestment opportunity options for the field and has taken the decision to fully impair the Barda Rash project.

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 the 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.

Field operations at the Ain Sifni block recommenced in September 2014 following a temporary suspension in August due to the regional security issues. The Simrit-4 well that was spudded in early 2014 has reached Target Depth (TD) in the Jurassic and Triassic reservoirs. The Simrit/Betnar Field Development Plan was approved by the Ministry of Mineral Resources on 27 November 2014. Simrit-4 testing is ongoing with one drill stem test (DST) completed in the Sargelu, one in the Naokelekan and two drill stem tests completed in the Kurra Chine in 2014. One DST in the Kurra Chine and one DST in the Mus/Adaiyah are scheduled for 2015. The DST in the Sargelu flowed up to 6,089 bopd with a maximum of 1% water cut on 28/64" choke and 893 psi well head pressure. The DST in the Naokelekan flowed up to 5,743 bopd with no water on 128/64" choke and 434 psi well head pressure. The DST in Kurra Chine C flowed up to 941 bopd with 80% water cut on 1" choke and 762 psi well head pressure, whilst the DST in Kurra Chine B flowed up to 2,630 bopd with 40% water cut on 76/64" choke and 397 psi well head pressure.

2015 outlook

Negotiations are ongoing with the MNR to determine the future work programme for Maqlub which includes completing the DST on Maqlub-1. The Partners' plan for Simrit is to recomplete one well and put two wells on production through an Early Production Facility in 2015.

An independent Competent Person's Report estimates Afren net Contingent Resources, including Maqlub, at 31.4 mmboe for Ain Sifni. Although there is an approved Field Development Plan, the project is uneconomic at current oil prices. Given the uncertainty surrounding a sustainable oil export mechanism, low oil price, and re-focused efforts toward our Nigerian assets, Management have decided to fully impair the Ain Sifni asset and are evaluating their options with respect to future capital commitments.

Financial review

Restatement of 2013 financial statements

During 2014, an independent review was performed by Willkie Farr & Gallagher (UK) LLP around the potential need for disclosure to the market of certain previous transactions. In light of additional information that was brought to light as a result of the independent review, the Company has undertaken an extensive review of the accounting for these three transactions. Management have reassessed certain accounting judgements made in the prior year and have concluded that it is appropriate to restate the financial statements at 31 December 2013 in relation to one of these transactions in order to reflect subsequent changes in judgements. No material adjustments were identified at 31 December 2012. As a result of the restatement, in 2013 cost of sales increased by US$178 million to US$1,179 million and the income tax credit for the year increased by US$178 million to US$335 million. Profit before tax fell by $178 million, however there was no change to profit after tax or net assets (refer to note 12 of the attached financial statements for further details).

1. Result for the year

Revenue

Revenue for 2014 was US$946 million (2013: US$1,644 million). The 42% year-on-year decrease reflects reductions in both sales' volumes and the average realised oil price.

Total working interest production from continuing operations in 2014 decreased by 32% to 31,819 excluding Barda Rash (2013: 47,112). This was primarily due to a reduced share of production and liftings from the Ebok field following the achievement of cost recovery of the initial development costs at the start of 2014.

The Group realised an average oil price of US$97/bbl (2013: US$106/bbl) before all royalties. The average Brent price for the year was US$97/bbl (2013: US$108/bbl).

Revenue excludes liftings of Ebok production by the holders of a net profit interest in the Ebok field which commenced in late 2014, however, barrels to satisfy this interest are included within production.

Cost of sales

Cost of sales for the year decreased by 47% to US$626 million (2013 restated: US$1,179 million). Reduced costs arising from lower net working interest production were more than offset by higher depreciation cost per barrel (driven by investment in the Group's producing fields to progress their development).

2013 cost of sales was restated and increased by US$178 million to reflect a change in judgement as to how the consideration of US$300 million paid in a prior year transaction with a field Partner should be split between tax and oil entitlement benefits acquired. The corresponding increase in the 2013 income tax credit is discussed in the Tax section below.

The Group achieved a normalised operating cost of US$18.1/boe (2013: US$14.0/boe). The increase from 2013 was mainlya consequence of lower production at Ebok which restricted opportunities for generating operational efficiencies. Normalised cost per barrel excludes costs and production from the Barda Rash field, one-off expenses and depreciation, depletion and amortisation. All other field-related costs are included on an annualised basis.

Impairments and operating result

The operating result for 2014 was severely impacted by impairments to property, plant and equipment (US$1,206 million; 2013: US$ nil), intangible exploration and evaluation assets (US$839 million; 2013: US$61 million) and goodwill (US$115 million; 2013: US$ nil).

The impairment of property, plant and equipment relates primarily to Barda Rash in the Kurdistan region of Iraq of US$933 million.An updated reserves report has been received which, on the basis of extended well testing and greater knowledge surrounding well performance compared to the previous report received in 2011, indicated Barda Rash only has contingent resources and, as such, a negative net present value. As these contingent resources are considered to require more capital to develop than aligns with the Group's priorities, it is not expected that the Company will undertake the development as previously planned. Given the current market environment there are significant uncertainties around any estimated sales value and a full impairment has been recognised. In addition, an impairment of US$273 million has been recognised in relation to Ebok in Nigeria as a result of the sharp decline in oil price towards the end of 2014.

Impairments to intangible exploration and evaluation assets includes full impairments of assets in the Kurdistan region of Iraq (US$265 million) following receipt of reserve reports and Ghana (US$39 million) following an economic evaluation. In addition, in line with the requirements of IFRS 6 'Exploration for and evaluation of mineral resources', following a review of licence requirements in conjunction with funding availability, full impairments have been recorded against a number of assets in Cote d'Ivoire, East Africa and South Africa. A partial impairment was also recognised against an asset in Nigeria (US$43 million) relating to unsuccessful well costs. With the sharp fall in the market oil price in the last quarter of 2014 and the continued low price environment, market prices for E&E assets are very difficult to determine hence, in order to comply with accounting standards, it was necessary for full impairments to be recognised. Despite this, the Group believes that upside potential remainsin respect of the exploration and evaluation portfolio and is optimistic of making recoveries on some of the assets that have been fully impaired through either development or sale.

In addition, the goodwill balance relating to OML 26 in Nigeria has been fully written off following an impairment review.

Finance charges and financial instruments

Finance costs for 2014 were US$67 million (2013: US$157 million). Afren benefited throughout 2014 from lower interest costs following its refinancing exercise in December 2013. The 2013 figure also included US$49 million of costs relating to the partial repurchase of the 2016 Bonds and 2019 Bonds. The Group capitalised US$66 million (2013: US$42 million) of finance charges in the year, largely relating to the development of the Barda Rash field which was financed using part of the Group's Bond proceeds. The subsequent write-off of these capitalised finance costs is included in the Barda Rash impairment charge.

For 2014, the Group recognised a loss from derivative financial instruments of US$9 million (2013: US$47 million). The US$38 million favourable change arose largely because of the fall in the market oil price during the last quarter of 2014.

Within other comprehensive income is a gain of US$88 million (2013: US$ nil) resulting from the settlement in December 2014of all oil price derivative contracts that had been entered into for 1 January 2015 onwards. Given the prevailing oil price and the Group's cash requirements, it was considered the optimum time to realise these gains. Accordingly, as at 31 December 2014, the Group did not have any oil price hedges in place. The US$88 million gain will be recognised in net profit in 2015 over the original life of the hedges.

Result before tax

The Group recorded a loss before tax from continuing operations for the year ended 31 December 2014 of US$1,955 million (2013 restated: profit of US$140 million). Normalised profit before tax was US$163 million (2013 restated: US$305 million). Normalised profit before tax is reconciled to the statutory loss/profit before tax in note 9 of the attached financial statements.

Tax

An income tax credit for 2014 of US$304 million (2013 restated: US$335 million) was recognised. This includes a deferred tax credit in relation to the Group's Ebok asset of US$251 million (2013 restated: US$625 million) reflecting the five-year tax holiday and the impact of the impairment review. The 2013 tax credit in respect of Ebok included a reversal of previous tax charges following the award of a five-year tax holiday period during 2013 which began in May 2011.

The 2013 tax credit, as restated, now also includes a gain of US$178 million arising from Ebok capital allowances acquired in 2013 which were previously assumed to have been paid for in full (refer to note 5 of the attached financial statements for further details).

The Group pays various other taxes locally in the areas in which it operates, in the form of royalties, withholding taxes and non-recoverable VAT. In 2014, these amounted to US$453 million (2013: US$419 million).

There are uncertainties surrounding the taxation treatment of marginal fields (see note 10: Contingent liabilities) and Pioneer status (see note 13: Post balance sheet events).

2. Financing and capital structure

Operating cash flow

Operating cash flow before movements in working capital decreased from the previous year by US$229 million to US$598 million (2013 restated: US$827 million). Reduced operating profit, for which the key factors are outlined above in the Revenue and Cost of Sales sections, was the key driver behind this decrease.

After movements in working capital, net cash generated by operating activities was US$539 million (2013 restated: US$1,038 million). This cash flow contributed towards the Group's US$769 million (2013: US$716 million) investment in its production, development, exploration and appraisal activities.

Financing

Gross debt at 31 December 2014 was US$1,304 million (2013: US$1,129 million). The main components of the US$175 million increase were an additional US$90 million drawdown on an existing Ebok facility, US$160 million drawdown on new facilities and US$80 million repayment in respect of a maturing facility.

The Group initiated a further refinancing project during the middle of 2014 which had to be postponed following the suspension of two Directors on 31 July 2014. When the Group was in a position to recommence the refinancing project it was severely impeded by a significantly higher risk premium and a declining oil price environment.

3. Our commitments

The Group had operating and capital commitments as at 31 December 2014 of US$644 million (2013: US$778 million), largely in respect of rig and field equipment leases and the Group's ongoing exploration and evaluation programmes.

4. Outlook

As described in note 1 of the attached financial statements, following the significant decline in oil prices prior to year end and their continued low level, in the absence of satisfactory completion of the Group's current refinancing plans the Group has insufficient funding to satisfy working capital requirements and forecast debt repayments as they fall due. The Group has reached an agreement with certain of its lenders and providers of debt regarding the injection of $200m of net Interim Funding to provide immediate liquidity to the Group and provide time to implement the required steps towards the completion of the wider recapitalisation to raise an additional US$55 million to US$105 million, as announced on 30 April 2015. As a result, the financial statements have been prepared on the basis the Group is a going concern, although the auditor has emphasised a material uncertainty regarding going concern, which is further described in the note 1 to the attached financial statements. 

The Group is working with its various stakeholders in order to secure the necessary funding and complete a financial and capital restructuring to overcome short-term liquidity problems and return to a stable financial platform. Through a strategy focused around its core producing assets, the Group intends to generate a reliable and durable profit stream.

Group statement of comprehensive income

For the year ended 31 December 2014

(1) Refer to note 12

Group balance sheet

For the year ended 31 December 2014

(1) Refer to note 12

Group cash flow statement

For the year ended 31 December 2014

(1) Refer to note 12

During the year the Group has settled a portion of its liability to net profit interest holders "in kind" through the provision of oil for an amount totalling US$45 million, which is not reflected in the Group cash flow statement.

Group statement of changes in equity

For the year ended 31 December 2014

1. Basis of accounting

Whilst the financial statements in this announcement have 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 on 30 April 2015.

The financial statements for the year ended 31 December 2014 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 2013 have been delivered to the Registrar of Companies and those for 2014 will be delivered following the Company's Annual General Meeting. The auditor has reported on those accounts and their report was unqualified, and did not contain statements under section 498(2) or (3) of the Companies Act 2006. The auditors have drawn attention to the going concern disclosure in note 1 of the 2014 financial statements by way of emphasis without qualifying the accounts. The prior year comparatives with the 2014 financial statements have been restated as discussed in note 12.

The financial statements have been prepared in accordance with 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.

Going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Operations review. The financial position of the Group at the year end, its cash flows, liquidity position and borrowing facilities are described in the Financial review.

Events following the dismissal of the Group's former CEO and COO have placed significant pressure on the Group's liquidity position, resulting in the Group having net current liabilities of US$459 million as at 31 December 2014.

The Company's inability to execute the planned refinancing in the middle of 2014, followed by the sharp decline in market oil prices, led the Directors to initiate an urgent review of the Group's capital structure, liquidity and funding requirements as announced on 20 January 2015. On 30 January 2015, the Group announced it had obtained from the lenders of the US$300 million Ebok debt facility a deferral of the US$50 million amortisation payment due on 31 January 2015. On 4 March 2015, the Group announced that the Board had decided at the expiration of a 30 day grace period not to pay US$15 million of interest which was due on 1 February 2015 under its 2016 Senior Notes.

On 13 March 2015, the Group announced a preliminary agreement for the receipt of Interim Funding and the Recapitalisation of the business. The agreement entered into by Afren together with certain noteholders under its 2016 Notes, 2019 Notes and 2020 Notes (Noteholders) and a majority of the lenders under the Group's existing US$300 million Ebok credit facility, is intended to result in the provision of US$255-US$305 million of net total funding before the end of July 2015. On 30 April 2015, the Company entered into definitive agreements with certain Noteholders and issued US$212 million of private placement notes (PPN), providing US$200 million in net cash to the Group. In conjunction with such agreement, the lenders under the Group's existing US$300 million Ebok credit facility agreed to the deferral of the US$50 million amortisation payments due on 31 January 2015 and 30 April 2015 until the completion of the implementation of the Recapitalisation (at which point it is expected that the amortisation payments will be further deferred until after the repayment of the New High Yield Notes - see below).

In connection with the Recapitalisation, on 30 April 2015 the Group also entered into a conditional agreement to raise US$55 million in additional net proceeds (after the repayment of the PPN) from the issuance of new High Yield Notes due in 2017 (New HY Notes). This amount may be increased to up to US$105 million in total additional net proceeds. In addition, as part of the Recapitalisation (i) 25% of the 2016 Notes, 2019 Notes and 2020 Notes (Existing Notes) will be converted to new equity in the Company; (ii) the remaining 75% of the Existing Notes will be extended to mature as to US$350 million in each of December 2019 and December 2020; (iii) the existing Ebok credit facility will be extended to 2019; (iv) new shares will be issued to subscribers to the New HY Notes and the PPN; and (v) the Company will undertake an equity offering of up to US$75 million to shareholders. The Group has also reached agreement with the lender of its Okwok/OML 113 facility to restructure and defer this facility until 2018.

The US$200 million net cash proceeds from the issuance of the PPN will be deposited in escrow, to be drawn down by the Group over the coming months. Withdrawals from escrow are required to be applied broadly in accordance with agreed financial forecasts, and are subject to an agreed drawdown schedule and the Group's continuing compliance with certain default conditions. The PPN would be repayable by April 2016 if not refinanced through the Recapitalisation.

In order for the Recapitalisation to be implemented there are other conditions that need to be fulfilled, including obtaining (i) the approval of requisite majorities of holders of the Existing Notes in connection with a scheme of arrangement of such Existing Notes; (ii) approval from the relevant courts in the UK and the US as to such scheme of arrangement; and (iii) agreement from the Group's remaining lenders. The Company will also seek the approval of shareholders in general meeting to the terms of the Recapitalisation, which is required in order to issue the new ordinary shares in connection with the Recapitalisation. If shareholder approval is not received, the Recapitalisation will still proceed, but on amended terms for the New HY Notes (see below).

As at 30 April 2015 Afren is in default under the terms of its 2016 Notes due to the non-payment of interest. The Company has received assurances from the ad hoc committee of Noteholders (which members hold in aggregate approximately 63% of the principal face amount of the 2016 Notes and approximately 50% of the total principal face amount of the Existing Notes) (Ad Hoc Committee) that the Ad Hoc Committee has no current intention to take enforcement action with respect to the 2016 Notes held by its members as a result of the failure to make payment of interest due under the 2016 Notes, on the basis that agreement has been reached with the Company and its key stakeholders on the terms of a consensual (but conditional) restructuring.

On 9 April 2015, the Group announced that the Board is taking advantage of a 30 day grace period not to pay US$12.8 million of interest which was due on 8 April 2015 under its 2019 Senior Notes. Accordingly, as at 30 April, Afren is not in default under the terms of its 2019 Notes due to the non-payment of interest, but the 30 day grace period expires on 8 May 2015. The Company has received assurances from the Ad Hoc Committee that it has no current intention to take enforcement action with respect to the 2019 Notes held by its members should the Company fail to make payment of interest due under the 2019 Notes.

There is a risk that one or more of these steps, may not be completed or satisfied and the Recapitalisation may not occur. If additional funds are not available to be drawn under the New HY Notes, and the Recapitalisation does not proceed, the Directors are of the opinion that the Group would become insolvent, absent an alternative proposal being received by the Company that is capable of being implemented.

If shareholder approval of the Recapitalisation is not received, the Ad Hoc Committee and the lenders under the Group's existing US$300 million Ebok credit facility have agreed to an alternative restructuring plan, whereby the economic terms of the New HY Notes will be amended, and the amendment and restatement of the Existing Notes will be revised (so that no new shares are issued). In addition, the New HY Notes will include a requirement for the Company to initiate a sale of the Group's business by the end of 2016, which together will mean that existing shareholders would be unlikely to see any return on their current investment.

On the basis that the Recapitalisation is successfully achieved as outlined above, the Group's financial footing and ability to continue in operation would be significantly strengthened. The Group's financial forecasts and projections for the next twelve months indicate that the Group would then be able to meet its obligations as they fall due, however, this assessment is sensitive to a number of downside risks such as any further significant deterioration in the outlook for oil prices, any significant disruption to the Group's production revenue stream due to operational or other factors, and the crystallisation of other risks such as those described in notes 10 and 13 to the financial statements, particularly if such downside risks were to materialise in combination. Therefore, the Group expects that it will still need to seek industry partnerships, strategic divestments and other fundraising transactions as necessary to build resilience against, or respond to, downside risks, capture the opportunity in the Group's portfolio and secure the Group's future.

The Directors recognise that the combination of the circumstances described above represents a material uncertainty that may cast significant doubt as to the Group's ability to continue as a going concern and that it may be unable to realise its assets in the normal course of business. Accordingly the auditors have included an emphasis of this matter in their report. Nevertheless, the Directors expect that the Recapitalisation will obtain all of the necessary approvals and consents as set out above and the Directors therefore have a reasonable expectation that the Group will be able to successfully navigate the present uncertainties and continue in operation. Accordingly the financial statements have been prepared on a going concern basis and no break up adjustments have been made.

2. (Loss)/earnings per ordinary share

(Loss)/earnings per share (EPS) is the amount of post-tax loss or 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 loss for the year attributable to equity shareholders of US$1,623.2 million (2013: US$478.3 million profit attributable to equity shareholders) divided by 1,102.8 million (2013: 1,090.8 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. Potentially dilutive securities have been excluded from the current year's computation as they would serve to decrease the loss per share.

The (loss)/profit and weighted average number of ordinary shares used in the calculation of the earnings per share are as follows:

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

The number of potentially dilutive securities which have been excluded from the current year's computation includes 9,600,082 relating to the share-based payments scheme and 36,535 relating to warrants.

3. Segmental reporting

(a) Geographical segments

The Group operates in three geographical markets which form the basis of the information evaluated by the Group: 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.

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 2013 income statement.

* The majority of the unallocated current segment assets relate to cash and cash equivalents in 2014.

The majority of the unallocated current segment assets relate to an amount receivable from a Partner in 2013.

(1) Refer to note 12.

Non-current assets in the following segments include:

* Relates to non-current assets within the regional offices.

Revenues were generated in Nigeria of US$945.8 million (2013: US$1,644.3 million), which includes US$11.3 million recycled from the hedging reserve as explained in note 4. All sales are to external customers. Included in revenues arising from Nigeria for the year ended 31 December 2014 are amounts of US$299.4 million, US$244.5 million, US$224.4 million and US$70.1 million (2013: US$252.0 million, US$251.8 million, US$211.3 million and US$183.3 million) relating to the Group's largest customers. As the sale of oil is made on global markets, the Group does not place reliance on the largest customers mentioned above.

 (b) Business segments

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

4. Hedging

During the year, in relation to the commodity deferred put options, the Group received a minimum amount if the market price of crude oil fell. These instruments were classified as cash flow hedges, with the portion of the gains and losses on the instruments that are determined to be an effective hedge taken to equity and subsequently recycled as the hedged transaction occurs and the ineffective portion, as well as any change in time value, recognised directly in the income statement for each period. During the year, a loss of US$7.0 million (2013: US$30.8 million) was reflected directly in the income statement in relation to these instruments and a further gain of US$98.8 million was taken to equity in the year, of which US$11.3 million was recycled in relation to hedged sales in 2014 with the balance of US$87.5 million to be recycled in future years. The Group had no open oil price derivative contracts as at 31 December 2014.

5. 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

The income tax credit represents the sum of tax currently payable and deferred tax. The 2013 amount includes a credit in respect of the reversal of prior period 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.

(1) Refer to note 12.

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

 (1) Refer to note 12.

During 2014, the Group continued to apply the benefits of a tax holiday in respect of its Ebok asset in Nigeria. Afren Resources Limited, the subsidiary which holds Afren's interest in the Ebok asset, received a certificate in 2013 awarding a five-year tax holiday which is effective from 1 June 2011 until May 2016. As a result, no income tax is payable in respect of the 2011-2016 period.

The adjustment in respect of prior years relates to the release of a provision following the conclusion of a tax audit within Afren Energy Resources Limited.

On 26 January 2015, Afren Resources Limited received a letter from the Nigerian Investment Promotion Commission informing that the initial tax holiday period had been reduced from five to three years. If enforced, the tax holiday would have effectively ceased on 31 May 2014, although two further annual periods of extension can be applied for in order to restore the full five-year term. Afren intends to contest the reduction and apply for the two annual extensions as necessary. If it is the case that neither of these actions are successful, the income tax credit would decrease by US$87.1 million (a sum of additional current income tax and a reduction in the deferred tax credit) from US$303.9 million to US$216.8 million, with a corresponding US$3.6 million increase in current income tax payable from US$15.7 million to US$19.3 million as at 31 December 2014, and a decrease in deferred tax asset from US$348.2 million to US$264.7 million as at 31 December 2014.

(b) Deferred taxation

(i) Recognised deferred tax assets and liabilities

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

Analysis of movement during the year - 2013 Restated(1)

(1) Refer to note 12. Table also restated to provide meaningful comparatives to 2014 balances.

(ii) Unrecognised deferred tax assets

At the balance sheet date, the Group also had tax losses (primarily arising in the UK) of US$533.7 million (2013: US$297.5 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$31.3 million (2013: US$23.3 million) in respect of share-based payments, property, plant and equipment and pensions in respect of which deferred tax assets have not been recognised as there is insufficient evidence of future taxable profits against which these tax losses could be recovered.

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

6. Intangible exploration and evaluation assets

Prospects deemed to be commercially viable, and transferred to property, plant and equipment during the current year, relate to

Okwok and OML 113 in Nigeria.

Amounts written off in 2014 include the write down of exploration and evaluation assets in the Kurdistan region of Iraq (US$265.2

million) following receipt of an updated third party reserve report and Ghana (US$39.0 million) following an economic evaluation. In addition, following a review of licence requirements in conjunction with the constraints affecting funding availability, full impairments

have been recorded against assets in Cote d'Ivoire (US$115.4 million), Kenya (US$129.5 million), Tanzania (US$36.3 million),

Madagascar (US$51.8 million), Seychelles (US$61.0 million), Ethiopia (US$82.1 million), Congo Brazzaville (US$1.6 million) and South Africa (US$14.3 million). A partial impairment was also recognised against OML 115 in Nigeria (US$42.9 million) relating to

unsuccessful well costs incurred on a specific prospect.

7. Property, plant and equipment

The impairment of property, plant and equipment relates to Barda Rash in the Kurdistan region of Iraq (US$932.6 million) and Ebok in Nigeria (US$273.0 million).

An updated reserves report has been received which, on the basis of extended well testing and greater knowledge surrounding well

performance compared to the previous report received in 2011, indicated Barda Rash only has contingent resources. As these

contingent resources are considered to require more capital to develop than aligns with the Group's priorities, it is not expected that