Pre-Annual General Meeting Information • May 10, 2013
Pre-Annual General Meeting Information
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THIS DOCUMENT IS IMPORTANT AND REQUIRES YOUR IMMEDIATE ATTENTION. If you are in any doubt about the contents of this Document or the action you should take, you are recommended to take advice from your stockbroker, bank manager, solicitor, fund manager or other independent financial adviser who is authorised under the Financial Services and Markets Act 2000 and who specialises in advising in connection with shares and other securities, or from another appropriately authorised financial adviser if you are taking advice outside the United Kingdom.
If you have sold or otherwise transferred all of your Afren Shares please send this Document, together with the accompanying Form of Proxy, to the purchaser or transferee or to the stockbroker, bank, or other agent through whom the sale or transfer was effected, for transmission to the purchaser or transferee. However, such documents should not be forwarded or transmitted in or into any jurisdiction in which such act would constitute a violation of the relevant laws in such jurisdiction. If you have sold or transferred only part of your holding of shares in Afren you should retain this Document and the accompanying Form of Proxy and consult the stockbroker, bank or other agent through whom the sale or transfer was effected.
This Document does not constitute or form part of any offer or invitation to purchase, otherwise acquire, subscribe for, sell, otherwise dispose of or issue, or any solicitation of any offer to sell, otherwise dispose of, issue, purchase, otherwise acquire or subscribe for, any security.
(incorporated in England and Wales with registered number 05304498)
This is not a prospectus but a shareholder circular. The distribution of this Document in jurisdictions other than the United Kingdom may be restricted by the laws of those jurisdictions and therefore persons into whose possession this Document comes should inform themselves about and observe any such restrictions. Failure to comply with these restrictions may constitute a violation of the securities laws of any such jurisdiction. This Document does not constitute an offer or an invitation to purchase or subscribe for any securities or a solicitation of an offer to buy any securities pursuant to the Document or otherwise in any jurisdiction in which such offer or solicitation is unlawful. Your attention is drawn to the letter from the Chairman of Afren which is set out on pages 4 to 10 of this Document, which contains the unanimous recommendation of the Directors that you vote in favour of the Acquisition and the resolution to be proposed at the General Meeting convened by the notice set out in this Document. You should not rely solely on the information summarised in this Document.
Notice of the General Meeting, which is to be held at 2.30 p.m. on 20 May 2013 at the offices of White & Case LLP, 5 Old Broad Street, London EC2N 1DW is set out at the end of this Document. A Form of Proxy for use in relation to the General Meeting is enclosed. To be valid, the Forms of Proxy should be completed, signed and returned in accordance with the instructions printed on them as to be received by the Company's registrars, Computershare Investor Services PLC, The Pavilions, Bridgwater Road, Bristol, BS99 6ZY or at the electronic address provided on the proxy form at www.eproxyappointment.com, in each case no later than 2.30 p.m. on 18 May 2013. Completion and return of a Form of Proxy will not preclude Afren Shareholders from attending and voting in person at the General Meeting, should they so wish.
Merrill Lynch International, which is authorised and regulated in the United Kingdom by the Financial Conduct Authority, is acting as sponsor to Afren in connection with the Acquisition and will not be responsible to anyone other than Afren for providing the protections afforded to clients of Merrill Lynch International or for providing advice in relation to the Acquisition, save that nothing in this Document shall limit or excude the responsibilities and liabilities of Merrill Lynch International which may arise under the Financial Services and Markets Act 2000 or the regulatory regime established thereunder.
| Page | ||
|---|---|---|
| PART 1 | EXPECTED TIMETABLE | 3 |
| PART 2 | CHAIRMAN'S LETTER | 4 |
| PART 3 | RISK FACTORS | 11 |
| PART 4 | PRINCIPAL TERMS OF THE AGREEMENT | 18 |
| PART 5 | FINANCIAL INFORMATION ON FHN | 22 |
| PART 6 | UNAUDITED PRO FORMA STATEMENT OF NET ASSETS | 52 |
| PART 7 | COMPETENT PERSON'S REPORT ON FHN | 56 |
| PART 8 | ADDITIONAL INFORMATION | 74 |
| PART 9 | DEFINITIONS AND GLOSSARY | 83 |
| NOTICE OF GENERAL MEETING | 86 |
| Date of this Document | 2 May 2013 |
|---|---|
| Latest time and date for receipt of Forms of Proxy | 18 May 2013 |
| General Meeting | 20 May 2013 |
| Expected date of Completion | 21 May 2013 |
Dated: 2 May 2013
This Document contains a number of "forward-looking statements" relating to Afren and FHN and the business sectors in which they operate. Generally, the words "will", "may", "should", "continue", "believes", "expects", "intends", "anticipates", "forecast", "plan" and "project" or similar expressions identify forward-looking statements. Such statements reflect the relevant company's current views with respect to future events and are subject to risks, assumptions and uncertainties that could cause the actual results to differ materially from those expressed or implied in the forward looking statements. Many of these risks, assumptions and uncertainties relate to factors that are beyond the companies' abilities to control or estimate precisely, such as future market conditions, changes in general economic and business conditions, introduction of competing products and services, lack of acceptance of new products or services and the behaviour of other market participants. Although Afren believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove to have been correct. Afren Shareholders should not, therefore, place undue reliance on these forward-looking statements, which speak only as of the date of this Document.
Subject to any obligations under the Listing Rules and/or the Disclosure and Transparency Rules, the Company undertakes no obligation to update publicly or review any forward-looking statement, whether as a result of new information, future developments or otherwise.
(Incorporated and registered in England and Wales under the Companies Act 1985 with registered number 05304498)
Mr. Egbert Imomoh (Non-Executive Chairman) Afren plc Dr. Osman Shahenshah (Chief Executive) Kinnaird House Mr. Shahid Ullah (Chief Operating Officer) 1 Pall Mall East Mr. Darra Comyn (Group Finance Director) London Mr. Ennio Sganzerla (Non Executive Director) SWI Y 5AU Mr. Peter Bingham (Non Executive Director) Mr. John St. John (Non Executive Director) Mr. Toby Hayward (Non Executive Director) Mr. Patrick Obath (Non-Executive Director)
Directors: Registered and Head Office
2 May 2013
Dear Shareholder,
On 25 March 2013, the Board of Afren announced that CBO Oil and Gas FHN Investment Service Vehicle Limited ("COGIL") had exercised the terms of an amended put option agreement (the "Agreement") under which Afren would acquire the beneficial interest in approximately 10.4% of the issued share capital of First Hydrocarbon Nigeria Company Limited ("FHN") (the "Option Shares") in exchange for an aggregate consideration of US37.05 million, payable in cash.
Currently, Afren holds 44.5% of the issued share capital of FHN through its subsidiary, Afren Nigeria Holdings. Following the Acquisition, Afren will hold (directly and indirectly) 54.8% of the issued share capital of FHN and will consolidate FHN in its Group financial statements. According to the NSAI Report, FHN had an estimated effective working interest in proved plus probable (2P) oil reserves before royalties of 60.6 mmboe as at 31 December 2012, representing approximately 29.0% of Afren's 209.8 mmboe of proven and probable reserves as at 31 December 2012. Accordingly, the Acquisition constitutes a Class 1 transaction (as defined in Chapter 10 of the UK Listing Rules) for Afren and therefore requires the approval of Afren Shareholders.
Therefore, the General Meeting has been convened for 2.30 p.m. on 20 May 2013 at the offices of White & Case LLP, 5 Old Broad Street, London EC2N 1DW to approve the necessary Resolution to implement the Acquisition. An explanation of the Resolution to be proposed at the meeting is set out in paragraph 7 below. The Board unanimously considers that the Acquisition is in the best interests of the Company and recommends that Afren Shareholders vote in favour of the Resolution.
I am writing to give you further details of the Acquisition, including the background to and reasons for it, to explain why your Board considers it to be in the best interests of Afren and to seek your approval of the Resolution.
The Acquisition will be implemented pursuant to the Agreement. On 4 April 2011 Afren entered into a put option deed with COGIL (the "Initial Deed") that granted COGIL a right (but not the obligation) (the "Option") to sell up to 15,000,000 ordinary shares in FHN to Afren at a price equal to US\$2.24 per FHN share in cash.
The Initial Deed was amended by a deed of variation dated 25 March 2013 (the "Deed of Variation"), pursuant to which (in consideration for certain other amendments for the benefit of Afren, including making completion of the Option subject to the prior approval of the Company's shareholders), Afren agreed to acquire up to 15,000,000 FHN shares at a price equal to US\$2.47 per FHN share in cash. On 25 March, COGIL exercised the Option and agreed to sell 15,000,000 shares in FHN, representing approximately 10.4% of the issued share capital of FHN, to the Company for an aggregate consideration of US\$37.05 million. The funding for the Acquisition will be provided from existing cash resources of the Company. Completion of the exercise of the Option is conditional upon the approval of the Company's shareholders (the "Condition"), but is not subject to any other condition precedent.
On the basis of the terms of the Agreement, the equity value for FHN would be approximately US\$378 million.
As a result of the Acquisition, Afren will consolidate FHN in its Group financial statements. According to the NSAI Report, FHN had an estimated effective working interest in proved plus probable (2P) oil reserves before royalties of 60.6 mmboe as at 31 December 2012, representing approximately 29.0% of Afren's 209.8 mmboe of proven and probable reserves as at 31 December 2012. Accordingly, the Acquisition constitutes a Class 1 transaction (as defined in Chapter 10 of the Listing Rules) for Afren and therefore requires the approval of Afren Shareholders.
To take advantage of the potential benefits of FHN remaining as an indigenous company in Nigeria, Afren's ownership in FHN will be structured in order to meet the criteria generally understood and sometimes required under Nigerian oil and gas industry policies for FHN to be classified as an indigenous Nigerian company, with the majority of its equity interest held by Nigerian owners (see "Indigenous company status in Nigeria" in paragraph 3 below). In order to do so, Afren intends to split its legal and beneficial holdings in FHN such that it is the legal owner of not more than 45% of the issued ordinary shares in FHN. The remaining portion of Afren's legal interest in FHN will be held in trust for the benefit of Afren by Adcax Investments Limited, a Nigerian-formed trust company (the "Trustee"). Accordingly, only the beneficial title to the Option Shares is proposed to be acquired by Afren, with the legal title being acquired by the Trustee while Afren will be the beneficiary of all the benefits accruing to the Option Shares.
If shareholder approval for the Acquisition is not obtained at the General Meeting, completion of the Option will not occur. In such circumstances, the Option will be deemed not to have been exercised and COGIL shall have no right to re-exercise the Option and Afren shall have no obligation to acquire any FHN shares from COGIL.
In conjunction with the Deed of Variation, on 25 March 2013 Afren also entered into an agreement with First City Monument Bank Plc ("FCMB") and COGIL (the "Side Agreement") in respect of the acquisition by Afren of certain indebtedness owed by COGIL to FCMB in the event that shareholder approval for completion of the acquisition of the Option Shares is not received. As part of the original acquisition by COGIL of the FHN shares the subject of the Option in 2011, FCMB made available a US\$33 million term loan facility to COGIL to finance COGIL's acquisition of such shares (the "COGIL Loan"). The COGIL Loan was due to be repaid in April 2013, or on the earlier disposal by COGIL of the relevant FHN shares (including under the terms of the Option).
Each of COGIL and FCMB anticipate that the COGIL Loan will be repaid from the proceeds of the sale of the Option Shares to Afren pursuant to the exercise of the Option by COGIL. Under the terms of the Deed of Variation, the sale of the Option Shares by COGIL is now subject to receipt of Afren shareholder approval, whereas no such approval was required under the Initial Deed. Accordingly, FCMB was concerned that if Afren's shareholders did not approve the acquisition of the Option Shares, COGIL would not be able to sell the Option Shares and use the proceeds to repay the COGIL Loan and COGIL may therefore be in default of its repayment obligations when the COGIL Loan became due for repayment.
Therefore in order to provide assurances to FCMB as to the repayment of the COGIL Loan by COGIL in circumstances where, due to the lack of Afren shareholder approval to the Acquisition, COGIL is unable to complete the sale of the Option Shares to Afren under the Option, on 25 March 2013 Afren entered into the Side Agreement with FCMB and COGIL. Pursuant to the Side Agreement, FCMB and COGIL have agreed to extend the date for repayment of the COGIL Loan until October 2013 or on the earlier disposal by COGIL of the relevant FHN shares.
Pursuant to the Side Agreement, Afren agreed with FCMB that, if Afren shareholder approval for the Acquisition is not obtained, it will purchase from FCMB all outstanding amounts due and payable under the COGIL Loan. Following any such acquisition of the COGIL Loan, Afren and CBO shall be entitled to seek purchasers for the Option Shares and Afren has agreed that the proceeds of the sale of the Option Shares shall be used to repay the amounts due under the COGIL Loan.
For so long as the acquisition of the Option Shares requires the approval of the Company's shareholders in accordance with the provisions of Chapter 10 of the Listing Rules, Afren undertakes that it shall not acquire the legal or beneficial interest in such shares, whether under the Option, in repayment of the COGIL Loan or otherwise, unless it has previously obtained such shareholder approval.
This Side Agreement shall only become operative as regards Afren if the Condition is not satisfied. It does not need separate Afren shareholder approval.
Further details about the Agreement, the Side Agreement, the trust arrangements and the terms of the Acquisition are set out in Part 4 of this Document.
FHN was established in June 2009 in direct response to the Nigerian government's policy to increase indigenous participation in the Nigerian upstream oil and gas sector and its commitment to deepening indigenous involvement in the sector at all levels. FHN was established by Afren with the support of two leading Nigerian financial institutions: FCMB and Guaranty Trust Bank Plc. Afren initially held 40% of FHN's issued shares, which increased to 45% in October 2010 through the issue of new FHN shares in repayment of a start up loan made by Afren to FHN and to 46.7% in October 2012 (when approximately five million shares were cancelled when a shareholder did not fully subscribe to its allocated shares). In February 2013, FHN issued additional new shares and Afren (through its subsidiary Afren Nigeria Holdings and via a trust structure) acquired further shares in FHN's enlarged issued share capital. As a result, Afren currently holds (directly or indirectly) 44.5% of the issued share capital of FHN.
In connection with the formation of FHN, Afren agreed to provide FHN and the FHN Board with assistance to develop FHN's business model and to support the refinement and execution of the business model over time, including preparation for a potential initial public offering on the Nigerian Stock Exchange. In addition, Afren agreed to provide technical and operational expertise and services to FHN to ensure that FHN becomes a world class Nigerian operator. FHN is supported by Afren in the execution of its technical, development, operational and acquisition strategies through the provision of technical and operator services, as well as the secondment of various Afren employees. Further details about the services provided to FHN by Afren is set out in paragraph 9 of Part 8 of this Document.
In October 2010, FHN entered into a purchase agreement with Shell Petroleum Development Company of Nigeria, Total E&P Nigeria and Nigeria Agip Oil Company to acquire a 45% interest in the OML 26 block located onshore Nigeria in Delta State. The purchase completed in December 2011, with FHN raising US\$230 million of syndicated debt and mezzanine finance to fund the field development and further inorganic growth.
The OML 26 block has two fields that are currently producing (Ogini and Isoko), with gross (100%) 2P oil reserves estimated at 134.6 mmboe. OML 26 has best estimate gross (100%) contingent (2C) oil resources estimated at 68.0 mmboe in Ogini, Isoko and three undeveloped fields (Aboh, Ovo and Ozoro), according to the NSAI Report.
The Nigerian Petroleum Development Company ("NPDC"), the oil and gas exploration and production subsidiary of Nigerian National Petroleum Company is the operator of OML 26, owning the other 55% of the block, and works closely in partnership with FHN on the re-development of the Ogini and Isoko fields, and the development of the Aboh, Ovo and Ozoro fields.
Initial work following the acquisition by FHN in 2011 was focused on the refurbishment of the existing gaslift compressor and the procurement and installation of a new gaslift compressor given the crucial requirements of gaslift for optimised production from the Ogini field. Interim metering is under commission and a Lease Automatic Custody Transfer Unit (LACT unit) is currently being installed. Efforts are now geared towards certain rigless and "quick win" opportunities, including low-cost workovers of existing wells. The 2013 work programme includes debottlenecking and expansion at the Ogini flowstation and construction of flowlines and gaslift lines for the new infill wells.
In 2012 gross average production from the Ogini and Isoko field totalled 4,432 bopd, of which 897 bopd were attributed to Afren, with production going beyond the ceiling of the asset pre acquisition of 8,000 bopd at times during the second half of 2012.
Under the proposed re-development plan for Ogini and Isoko, further workovers of existing wells will be embarked on using workover hoists, alongside a drilling campaign of new development wells and upgrade of surface facilities. These activities will be expected to increase production to more than 40,000 bopd through a phased development process by 2015 and ultimately take production to 50,000 bopd. The FHN board expects to incur approximately US\$350 million in capital expenditure over the next five years in relation to this re-development plan.
For the year ended 31 December 2012, FHN generated US\$112.4 million in revenue, incurring a pre-tax operating loss of approximately US\$12.1 million. The net revenues and loss attributable to the Acquisition in respect of the year ended 31 December 2012 were approximately US\$11.7 million and US\$1.3 million respectively. Audited financial information on FHN for the three financial years ended 31 December 2012 are set out in Part 5 of this Document.
FHN's current share capital comprises approximately 130 million issued ordinary shares, with a further 14.85 million issued but deferred shares issued to the board and certain members of management of FHN and options over 643,000 ordinary shares issued to certain employees of FHN. These deferred shares have vested, but will only be transferred to the holders upon an exit event for FHN (such as an initial public offering by FHN, but not as a result of the Acquisition or any further consolidation by Afren).
Although there is currently no Nigerian legislation that defines an indigenous Nigerian company, Afren are structuring their investment in FHN to take advantage of potential future benefits from FHN being an indigenous company.
The Nigerian Oil and Gas Industry Content Development Act 2010 (the "Nigerian Content Act") affects the operations of FHN. The Acquisition has been structured so that FHN will remain as a "Nigerian Company" for the purposes of the Nigeria Content Act under which a minimum of 51% Nigerian ownership is required to qualify as a Nigerian Company. This should mean that FHN will be given first consideration in the award of oil blocks, oil field licences or other contract awards made in the Nigerian oil and gas industry.
More broadly within the Nigerian oil and gas industry, the term "indigenous company" has evolved from a combination of inferences drawn from varying equity participation restrictions, which affect specific oil industry contracting regimes in Nigeria. Although, OML 26 was not awarded under any of such regimes with government specified equity restrictions, FHN acquired its 45% interest in OML 26 on the basis that it was owned 55% by Nigerian nationals, as was requested by the seller, the Shell Petroleum Development Company of Nigeria.
Indigenous status in relation to FHN is therefore used to mean that the total direct and indirect holdings of shares within FHN by non-Nigerian persons or non-Nigerian companies amounts to no more than 45% of the company's outstanding share capital at any time (or such other greater percentage as may subsequently be prescribed from time to time pursuant to any Nigerian law, regulation or policy regulating the indigenous status of Nigerian companies).
In 2008, with a view to reforming the oil sector in Nigeria, a new Petroleum Industry Bill was submitted to the National Assembly. A revised 2012 version seeks to introduce a definition for "indigenous petroleum companies" but as at the date of this document, the bill has yet to be passed as a law. Presently, there is no certainty with regard to when the Petroleum Industry Bill will be passed into law.
FHN's board of directors comprises a combination of local knowledge and experience, technical and industry knowledge and understanding, corporate governance experience and business acumen. The board of directors of FHN plays an active role in the development of FHN's businesses strategy. The board of FHN includes two Afren representatives, Egbert Imomoh and Osman Shahenshah, out of a total of nine directors. FHN's chief executive officer is 'Labi Ogunbiyi, previously an executive director of Afren. FHN has also put in place an experienced Nigerian senior management team with a proven track record of securing local and international financing for oil and gas assets in Nigeria and of developing assets from exploration, through to appraisal, development and production quickly.
The Company notes that one of the remaining shareholders in FHN, Fioul Investments Limited ("Fioul"), is a nominee company incorporated in Nigeria that holds FHN shares on trust on behalf of certain of the Directors and members of senior management of the Company, as well as certain members of FHN's management. Fioul currently owns 18,000,000 FHN shares, with a majority of such shares being held by Nigerian nationals. A further 3,570,000 FHN shares are held, subject to certain vesting conditions, by certain Directors who are members of the FHN board of directors.
In 2010, certain members of Afren's senior management (as well as members of FHN's management) agreed to make an aggregate cash investment of US\$2.34 million in FHN in order to align the interests of Afren, its management and the initial investors in FHN in promoting increased shareholder value in Afren through FHN's successful acquisition and development of OML 26, and potential further acquisitions by FHN from the major oil & gas companies in Nigeria.
The investment was in respect of 15% of FHN's then issued share capital at a price of US\$0.13 per share. At the time of such investment, FHN did not own any assets, although it had entered into a conditional sale and purchase agreement to acquire a 45% interest in OML 26. This cash investment in FHN was structured via Fioul, with certain trust arrangements implemented in order to ensure that FHN's indigenous status was not jeopardised by this acquisition by non-Nigerian investors. The FHN shares owned by Fioul are held by Fioul under a nominee trustee structure until an initial public offering of FHN or an earlier crystallisation event that provides long term liquidity for FHN's investors (which does not include the Acquisition).
The aggregate holdings of FHN shares by Fioul and Directors currently represent approximately 14.9% of FHN's fully diluted share capital. Further details on the interests of certain of the Directors and Afren PDMRs in FHN shares are set out in paragraph 5 of Part 8 of this Document.
The rationale for the Acquisition underlines Afren's stated strategy of delivering long-term value to shareholders and other stakeholders by acquiring and developing a balanced and diversified portfolio of quality assets across the whole Exploration and Production value chain. Central to this is Afren's operations in Nigeria, where it has positioned itself as partner of choice to assist in monetising the country's extensive remaining resources. Having successfully delivered on two high quality offshore Nigerian development projects in Ebok and Okoro, together with six further appraisal and exploration projects, Afren now has a track record of delivering projects in record time. The proposed Acquisition will allow Afren to further consolidate its position onshore Nigeria.
The Acquisition will enable Afren to immediately consolidate its holding of FHN's reserves and production as a subsidiary. Based on data provided in the NSAI Report, the Acquisition will result in Afren achieving a material increase in net Proved and Probable Reserves from 209.8 mmboe as at 31 December 2012 to 270.3 mmboe, representing an increase of approximately 29%.
The Company through the trust structure may, in future, look to acquire further shares in FHN in order to increase its overall investment in FHN.
On 22 March 2013 Afren signed a new US\$300 million Ebok facility which has a three year term and bears interest at Libor plus 4-4.8%. The facility will be used to refinance the existing Ebok reserve based lending facility amount of approximately US\$185 million as well as fund ongoing capital expenditure and general corporate requirements including intra group loans.
The performance of the Ebok and Okoro fields which has contributed to strong financial results and operating cash flows achieved by the Group in 2012 is expected to continue throughout 2013. The Group will continue to look to fund its exploration and appraisal activities through its operational cash flows, whilst also seeking opportunities to increase its capital strength.
FHN generated its first revenues in 2012, following the first lifting of approximately 194,000 bbls on OML 26 in April 2012 and further liftings allocation during the second half of 2012. In 2013, FHN will continue to focus on developing OML 26, with plans to drill two further producing wells in commencement of a drilling programme of 30 wells.
Currently, Afren directly and indirectly holds 44.5% of the issued share capital of FHN. Following the Acquisition, Afren will hold (directly and indirectly) 54.8% of the issued share capital of FHN and will consolidate FHN in its group financial statements. According to the NSAI Report, FHN had 60.6 mmboe in proved and probable reserves as at 31 December 2012, representing approximately 29% of Afren's 209.8 mmboe of proved and probable reserves as at 31 December 2012. Following completion of the Acquisition, pro-forma net proven and probable reserves of the Group are expected to be approximately 270.3 mmboe.
FHN generated US\$112.4 million in revenue, incurring a pre-tax operating loss of approximately US\$12.1 million. The net revenues and pre-tax operating loss attributable to the Acquisition in respect of 2012 were approximately US\$11.7 million and US\$1.3 million respectively. The Company expects the Acquisition to initially have a dilutive effect on the Group's earnings.
An unaudited pro forma statement of net assets as at 31 December 2012 illustrating the effects of the Acquisition on Afren's net assets is set out in Part 6 of this Document. This shows that had the Acquisition taken place on that date, the consolidated net assets of the Enlarged Group would have been approximately US\$1,452 million (based on the assumptions set forth in the footnotes to the unaudited pro forma statement of net as set out in Part 6 of this Document).
The notice convening the Afren General Meeting to be held at the offices of White & Case LLP, 5 Old Broad Street, London EC2N 1DW on 20 May 2013 at 2.30 p.m. is set out at the end of this Document. The purpose of the meeting is to approve the Resolution in connection with the Acquisition. A summary of the Resolution is set out below.
The Resolution is to approve the Acquisition and to authorise the Board to make such waivers and extensions and non material amendments or variations to the terms and conditions of the Acquisition and to do all things as it considers necessary or expedient in connection with the Acquisition.
The full text of the Resolution is set out in the notice convening the General Meeting at the end of this Document. In the event that the Resolution is not passed, the Acquisition will not proceed.
You will find enclosed with this Document a Form of Proxy for use at the General Meeting or at any adjournment thereof. You are requested to complete and sign the Form of Proxy whether or not you propose to attend the General Meeting in person in accordance with the instructions printed on it and return it as soon as possible, but in any event so as to be received no later than 2.30 p.m. on 18 May 2013, by the Company's Registrar, Computershare Investor Services PLC, The Pavilions, Bridgwater Road, Bristol, BS99 6ZY or at the electronic address provided on the proxy form at www.eproxyappointment.com.
CREST members may also choose to utilise the CREST electronic proxy appointment service in accordance with the procedures set out in the notice convening the General Meeting at the end of this Document. The lodging of the Form of Proxy (or the electronic appointment of a proxy) will not preclude you from attending and voting at the meeting in person if you so wish.
Your attention is drawn to the further information set out in Parts 3 to 8 of this Document.
The Board considers that the Resolution is in the best interests of the shareholders of Afren and the Afren Shareholders as a whole.
Accordingly, the Board unanimously recommends that Afren Shareholders vote in favour of the Resolution to be put to the General Meeting as they intend to do in relation to their own individual holdings which amount in total to 13,635,031 Afren Shares, representing approximately 1.25%, of the existing issued share capital of Afren as at 30 April 2013, the latest practicable date prior to publication of this Document.
Yours faithfully,
Egbert Imomoh Chairman
The following risk factors should be considered carefully when deciding whether or not to vote in favour of the Resolution to be proposed at the General Meeting. The risk factors should be read in conjunction with all other information relating to the Acquisition and the Enlarged Group contained in this document. The risks and uncertainties set out below are those which the Directors believe are the material risks relating to the Acquisition and to the Enlarged Group, material new risk factors for the Group as a result of the Acquisition and existing material risks for the Group which will be impacted by the Acquisition. If any or a combination of these risks actually materialise, the business, operations, financial conditions and prospects of the Group and, following Completion of the Acquisition, the Enlarged Group as appropriate could be materially and adversely affected. The following is not exhaustive and does not purport to be a complete explanation of all the risks involved. Additional risks and uncertainties not presently known to the Directors, or which the Directors currently consider to be immaterial, may also have a material adverse effect on the Acquisition and on the Enlarged Group if they materialise. If any of the risks actually materialise, the market price of the Afren Shares could decline and you may lose all or part of your investment.
There can be no guarantee that the Enlarged Group will realise any or all of the anticipated benefits of the Acquisition, either in a timely manner or at all. The process of estimating reserves and resources that may be developed and produced with respect to FHN is based on volumetric calculations and analogies to similar types of fields. As a result, the estimation of the reserves and resources at FHN may be materially inaccurate. If this is the case, and the Enlarged Group has incurred significant costs, this could have an adverse impact on the business, results of operation and the financial condition of the Enlarged Group.
Furthermore, integrating operations and personnel and pre or post completion costs may prove more difficult and/or expensive than anticipated, thereby rendering the value of the assets acquired less than the amount paid. The integration of acquired businesses requires significant time and effort on the part of Afren's management. Integration of new businesses can be difficult, because Afren's operational and business culture may differ from the cultures of the businesses it acquires, unpopular cost cutting measures may be required, internal controls may be more difficult to maintain and control over cash flows and expenditures may be difficult to establish. While Afren has successfully completed the integration of the businesses it has acquired thus far, it could experience difficulties in integrating the acquisition of FHN and consolidating its operations as successfully, which could have an adverse effect on its financial condition and results of operations.
The reserves and resources data and forward looking statements contained in this document in respect of FHN are estimates only and should not be construed as representing exact quantities. They are based on ownership, entitlement, geophysical, geological and engineering data, and other information assembled by Afren, as well as Afren's assumptions based on its experience in developments of a similar nature. The estimates may prove to be incorrect and potential investors should not place undue reliance on the forward-looking statements contained in this document concerning FHN's reserves and resources. If the assumptions upon which the estimates for FHN's hydrocarbon reserves and resources prove to be incorrect, the Enlarged Group may be unable to recover and produce the estimated levels or quality of hydrocarbons and the Enlarged Group's business, prospects, financial condition or results of operations could be adversely affected.
The implementation of the Acquisition, as a class 1 transaction, is subject to the approval by the Shareholders in accordance with the rules of the UKLA. If shareholders do not vote in favour of the Resolution at the General Meeting, which approval shall require a simple majority of those shareholders attending and voting (whether in person or by proxy), the Acquisition will not complete.
If the Acquisition does not complete, Afren will continue to hold only 44.5% of the issued share capital of FHN and therefore will not be able to consolidate FHN in its Group financial statements. This means that Afren will not be able to attribute FHN's proven and probable reserves, amounting to 60.6 mmboe in proven and probable reserves as at 31 December 2012 (according to the NSAI Report), representing approximately 29.0% of Afren's 209.8 mmboe of proven and probable reserves as at 31 December 2012, to its pro forma net proven and probable reserves.
The terms of the Acquisition, including this condition, are more fully described in Parts 2 and 4 of this Document.
Under Nigeria's petroleum laws, the prior consent of the Nigerian Minister of Petroleum Resources (the "Minister") is required for the takeover or assignment ("Transfer") of any participating interest held in an upstream oil and gas producing asset. Prior ministerial consent is also required where the Transfer of a participating interest occurs by way of a change of control arising through the acquisition of shares. Based on legal advice, the Company considers that the Acquisition has not resulted in a change in control of FHN. The Acquisition has been structured so that Afren will not have control of a majority of the votes conferred by the ordinary shares in FHN, but will only have acquired the beneficial interests in the Option Shares (including the attaching economic rights), to the exclusion of legal ownership and of the accompanying voting rights in such FHN shares. Accordingly, as Afren does not have voting control, this would not amount to a change of control of FHN in favour of Afren which would have triggered the requirement for ministerial consent.
However, there is a risk that the Minister may consider that a change in control of FHN has occurred by reason of the Acquisition. Where a view is taken that a change in control has occurred in FHN, it would render the transfer of the underlying beneficial interest in OML 26 inchoate until approved by ministerial consent. This means that although the transfer of shares will be valid and effective in law, the beneficial rights that would ordinarily follow such acquisition and accrue to Afren i.e. the equivalent indirect beneficial interest in OML 26, will remain in abeyance until ministerial consent is obtained. Ministerial consent is not granted automatically, it is granted at the discretion of the Minister subject to his consideration of the financial standing, technical expertise and political goodwill of the potential acquirer; therefore, there is a risk that the Minister may not grant his consent to the Acquisition or that the process for obtaining the consent may be unduly delayed. If the Minister refuses to grant his consent to a Transfer, the refusal cannot be subjected to judicial review in Nigeria.
Under the terms of the Initial Deed (as varied by the Deed of Variation), completion of the Acquisition is not subject to receipt of the consent of the Minister to the Acquisition. Accordingly, if the Acquisition completes and the Minister subsequently determines that prior consent for the Transfer should have been obtained, the Minister may refuse to recognise the Acquisition and continue to deal with FHN and OML 26 as if the Acquisition never occurred. If the Minister refuses to recognise the Acquisition, Afren will not be able to appropriate the beneficial rights accruing by reason of the Acquisition.
Under the Nigerian Petroleum Act of 1969 (as amended) (the "Petroleum Act"), the Minister may validly revoke an oil mining lease interest if in his opinion a lessee has failed to comply with any provision of the Petroleum Act. It therefore follows that a possible (albeit unlikely) consequence of the failure to obtain prior ministerial consent to the Acquisition (where it is construed to be a change in control of FHN) could be the revocation of the lease or any aspect of it. Any such revocation would have a material and adverse effect on FHN's business, prospects, financial condition and results of operations.
The Nigerian Content Act establishes the Nigerian Content Development and Monitoring Board (the "NCDM Board"), which administers the provisions of the legislation and ensures that procurement carried out in the oil and gas sector in Nigeria complies with local content requirements stipulated in the Nigerian Content Act. The Nigerian Content Act defines a "Nigerian Company" as one incorporated in Nigeria with a minimum of 51% of such company's shareholding being held by Nigerians. It does not specifically require that such ownership by Nigerians be both legal and beneficial or that a company be a "Nigerian Company" for the purposes of compliance with the legislation. In practice, however, the NCDM Board has often demanded and advised that a company operating in the Nigerian oil and gas industry must be a Nigerian Company as defined under the Nigerian Content Act.
Practical experience to date has shown that the NCDM Board's primary concern with respect to its regulation of the ownership of companies in the Nigerian oil and gas industry has been in relation to service companies. The NCDM Board has not focused its attention on the ownership of exploration and production companies. If the NCDM Board were to take the view that such ownership by Nigerians in exploration and production companies must be both legal and beneficial, then there is a risk to the Enlarged Group that, by reason of the Acquisition, FHN will no longer be considered a "Nigerian Company" as contemplated under the Nigerian Content Act and will therefore be ineligible for the benefits and privileges accorded to indigenous companies under the Nigerian Content Act. If FHN is not considered to be a Nigerian Company as contemplated under the Nigeria Content Act, there is the risk that FHN will not be given first consideration in the award of oil blocks, oil field licences or other contract awards made in the Nigerian oil and gas industry.
Whilst the Company does not expect the Nigerian Content Act to have a negative impact on the business of FHN as a Nigerian Company, in the event FHN is not classed as a Nigerian Company (or indigenous company) the additional operating costs and compliance requirements may have a material adverse effect on the operations and financial condition of FHN following completion of the Acquisition.
Although the specific nature of trust arrangements adopted by companies seeking to maintain Nigerian Company status under the Nigerian Content Act may vary, the Company believes that the arrangement structured pursuant to the Trust Deed enables FHN to remain as an indigenous company under Nigerian oil and gas industry practice. To date, the Company is not aware of any instance where the government of Nigeria has unilaterally challenged any similar arrangements in the upstream industry as being contrary to Nigerian law and/or policy or where any trust structure similar to that which has been adopted to effect the Acquisition has been subject to judicial interpretation. While the Company believes that the terms of the Trust Deed should help to minimise any risks associated with its ownership structure of FHN, there can be no assurance that this will be the case.
NPDC, the oil and gas exploration and production subsidiary of Nigerian National Petroleum Company is the operator of OML 26, owning the other 55% of the block, and works closely in partnership with FHN on the re-development of the Ogini and Isoko fields, and the development of the Aboh, Ovo and Ozoro fields. Although FHN is able to exert a degree of control, primarily through the budget approval mechanism, NPDC is the designated operator with the main responsibility for conducting the business of OML 26. As a result, FHN has limited control over the operations and timing of the exploration and development of such properties.
FHN and its joint venture party must comply with the requirements of any applicable licence or related agreement pursuant to which it operates, in addition to joint operating agreements or other arrangements governing its relationship with NPDC as its joint venture partner, as applicable. There is a risk that FHN may suffer unexpected costs or other losses if NPDC does not meet its obligations. FHN may also be subject to claims by NPDC regarding potential non-compliance with its own obligations. It is also possible that the interests of FHN on the one hand and those of NPDC on the other will not always necessarily be aligned resulting in possible project delays, additional costs or disagreements.
In addition, failure by FHN's joint venture partner to comply with the obligations under the relevant licenses or the agreements pursuant to which FHN operates may lead to fines, penalties, restrictions and withdrawal of licenses or the agreements under which it operates. In the event that NPDC becomes insolvent or otherwise unable to pay its debts as they come due, licenses or agreements awarded to them may revert to the relevant government authority who will then reallocate the licence.
FHN anticipates that the effect of this risk may be mitigated through the relevant government authority's permission for FHN to continue operations at a field during a reallocation process. However there is a risk that FHN may not be able to continue operations pursuant to these reclaimed licenses or during the reallocation period. The occurrence of any of the situations described above could materially and adversely affect FHN's business, prospects, financial condition and results of operations.
From time to time, Afren and FHN may be subject to litigation arising out of their operations, including claims that may be without merit. Damages claimed under such litigation may be material or may be indeterminate, and the outcome of such litigation may materially impact Afren's and, if the Acquisition completes, the Enlarged Group's business, results of operations or financial condition.
For example, on 18 May 2012 a writ of summons was issued by various individual claimants, for themselves and on behalf of (inter alia) the Isoko National Youth Movement and the Iyede Ame community, against Afren Group plc, FHN, SPDC, NPDC, NNPC and the Minister of Petroleum Resources. The writ alleged that the acquisition of onshore facilities, including OML 26 and OML30, required the prior consent of the claimants and was therefore illegal, null and void. The claimants sought a court order setting aside the sale, damages amounting to N=2,000,000,000, and an order granting them 10% of the daily oil production quantum from the defendants. On 15 June 2012, Afren and FHN applied for an order striking out the writ of summons and dismissing the suit and the proceedings have been adjourned to May 2013. Afren has been advised and strongly believes the case is completely without merit.
While Afren and FHN assesses the merits of each lawsuit and defends itself accordingly, it may be required to incur significant expenses or devote significant resources to defending itself against such litigation. In addition, the adverse publicity surrounding such claims may have a material adverse effect on Afren's and, if the Acquisition completes, the Enlarged Group's business.
FHN currently does business in Nigeria, a jurisdiction that has been allocated low scores on Transparency International's "Corruption Perception Index". Doing business in international developing markets brings with it inherent risks associated with fraud, bribery and corruption. In addition, the oil and gas industries have historically been shown to be vulnerable to corrupt or unethical practices.
Instances of fraud, bribery and corruption, and violation of laws and regulations in Nigeria could have a material adverse effect on its results of operations and financial conditions. In addition, as a result of the Group's anti-corruption training programmes, codes of conduct and other safeguards, there is a risk that the Group could be at a commercial disadvantage and may fail to secure contracts within jurisdictions that have been allocated a low score on Transparency International's "Corruption Perception Index" to the benefit of other companies who may not have or comply with such anticorruption safeguards.
The Nigerian Government is conducting on-going corruption-related investigations and other investigations into the oil industry in Nigeria. In particular, the Nigerian Government has reviewed historical taxes of exploration and production companies, investigated production costs and generally re-negotiated license and lease renewals, and in some cases holders were required to pay additional amounts for the renewal of their licenses. The Nigerian Government also ordered a forensic audit of the NNPC's accounts and has sought to make the oil and gas industry and operations more transparent. In early 2012, the Nigerian Government inaugurated the Petroleum Revenue Special Task Force, a body set up primarily to investigate, verify and recover all upstream and downstream petroleum revenues accruing and payable to the Nigerian Government. This task force is also charged with the responsibility of developing a system to determine and monitor all crude oil production and exportation in Nigeria.
Afren is not aware of any adverse findings relating to OML 26 or FHN, or of any current or threatened investigations relating to OML 26 or FHN, but if any such investigations or findings are made and substantiated in the future against the Enlarged Group, its Directors, officers, employees or joint venture partners, or such persons or partners are found to be involved in corruption or other illegal activity, this could result in criminal or civil penalties, including substantial monetary fines, against the Enlarged Group, its Directors, officers, employees or joint venture partners, loss of permits or licences, a refusal to by a governmental or regulatory body to renew a licence or permit.
The Group maintains regular anti-corruption training programmes, strict codes of conduct and other safeguards designed to prevent the occurrence of fraud, bribery and corruption. The anti-corruption training programmes, strict codes of conduct and other safeguards will apply to the operations of Enlarged Group. However notwithstanding these strict controls, it may not be possible for the Group to detect or prevent every instance of fraud, bribery and corruption in every jurisdiction in which its employees, agents, sub-contractors or joint venture partners are located and accordingly the Group could be subject to civil and criminal penalties and reputational damage.
Any such findings in the future could damage the reputation of the Enlarged Group and its ability to do business, including by affecting its rights in relation to OML 26 or by the loss of key personnel, and could have a material and adverse effect on the business, prospects, financial condition and results of operations of the Enlarged Group. Furthermore, alleged or actual involvement in corrupt practices or other illegal activities by joint venture partners, or others with whom the Enlarged Group conducts business, could also damage the reputation and business of the Enlarged Group and have a material and adverse effect on its business, prospects, financial condition and results of operations.
Afren's and FHN's current operations are subject to licences, regulations and approvals of governmental authorities for exploration, development, construction, operation, production, marketing, pricing, transportation and storage of oil, taxation and environmental and health and safety matters. Afren cannot guarantee that such licences applied for will be granted or, if granted, will not be subject to possibly onerous conditions. Any changes to exploration, exploration and production, or production licences, regulations and approvals, or their availability to Afren or FHN may adversely affect the Group's assets, plans, targets and projections.
Afren is subject to extensive government laws and regulations governing prices, taxes, royalties, allowable production, waste disposal, pollution control and similar environmental laws, the export of oil and many other aspects of the oil business. Although Afren believes it has good relations with the current government of Nigeria, there can be no assurance that the actions of present or future governments in Nigeria, or of governments of other countries in which Afren operates will not materially adversely affect the business or financial condition of the Enlarged Group.
Furthermore, the oil and gas sector in Nigeria, in particular, is still developing, and there have been a number of changes in policy affecting the sector. Nigeria is pursuing a number of new policy directions with the aim of restructuring its upstream and deregulating its downstream sectors, but the adoption of new regulations and the implementation of suggested reforms may be subject to political and economic influences, which could create uncertainty in relevant sectors.
In August 2007, the Federal Government of Nigeria announced the overhaul of the oil sector and stated that it would be implementing reforms to deal with the deregulation and privatisation of the NNPC. These reforms were first suggested by the Oil and Gas Sector Reform Implementation Committee set up in 2000 and another committee set up by the National Council on Privatisation, but the mooted plans were rejected by former president Olusegun Obasanjo.
The Petroleum Industry Bill – In 2008, a draft Petroleum Industry Bill ("PIB") was proposed as a new legal and regulatory framework for the oil and gas industry in Nigeria to replace several other laws. The PIB underwent several legislative reviews in the National Assembly between 2009 and 2011 and in July 2012, a Special Task Force constituted by the Nigerian President submitted a harmonised draft of the PIB to the National Assembly for parliamentary consideration and enactment. Presently, there is no certainty with regard to when the PIB will be passed into law and judging by the nature of the opposition to some of its provisions as recently expressed by members of the National Assembly, the PIB might still require substantial modification before it is enacted as law. In the meantime, the uncertainty surrounding both the terms of the PIB and its possible date of enactment make it difficult to assess the possible impact the PIB will have on the oil and gas industry in Nigeria.
Nigerian Content Legislation – The Nigerian Content Act will impact upon Afren's and, if the Acquisition is completed, the Enlarged Group's operations in Nigeria. Under the Nigerian Content Act, the NCDM Board administers the provisions of the legislation and ensures that procurement carried out in the oil and gas sector in Nigeria complies with local content requirements stipulated in the Nigerian Content Act. The Nigerian Content Act does not specifically require that a company be a "Nigerian Company" for the purposes of compliance with the legislation. In practice, however, the NCDM Board has often demanded and advised that a company operating in the Nigerian oil and gas industry must be a Nigerian Company as defined under the Nigerian Content Act. If FHN is not considered to be a Nigerian Company as contemplated under the Nigeria Content Act, there is the risk that FHN will not be given first consideration in the award of oil blocks, oil field licences or other contract awards made in the Nigerian oil and gas industry.
To the extent the Enlarged Group is not the operator of its oil and gas properties, including OML 26, it will be dependent on third parties for the timing of activities related to such properties and will not be able to unilaterally direct or control the activities of the operators or the costs of production and exploration of such operations. In addition, the success of the Enlarged Group will be largely dependent upon the performance of the operator's key employees. Any mismanagement of an oil or gas property by the operator may result in delays or increased costs to the Enlarged Group's non-operated exploration, development and production activities, which could materially and adversely affect the Enlarged Group's business, financial condition, results of operations and prospects.
In addition, failure by any party to comply with the obligations under the relevant licences or the agreements pursuant to which the oil and gas assets are operated may lead to fines, penalties, restrictions, withdrawal of licences and termination of such agreements, and/or the obligation for the Enlarged Group to meet other parties' obligations under the relevant licence or agreement. This could lead to the disruption or suspension of operations in the relevant licence area.
The terms of any relevant operating agreement generally impose standards and requirements in relation to the operator's activities. While the Afren Group has deliberately acquired interests in oil and gas properties that are operated by, what it believe to be, reputable operators, there can be no assurance that any such operator will observe such standards or requirements. There is a risk that other parties with interests in the Enlarged Group's oil and gas properties may elect not to participate in certain activities relating to those properties and which require that party's consent. In these circumstances, it may not be possible for such activities to be undertaken by the Enlarged Group alone or in conjunction with other participants at the desired time or at all. Other participants who have invested in the Enlarged Group's oil and gas properties may default in their obligations to fund capital or other funding obligations in relation to such properties. In such circumstances, the Enlarged Group may be required under the terms of the relevant operating agreement to contribute all or part of any such funding shortfall.
The Group's and FHN's exploration and development operations must be carried out in accordance with the terms of its production sharing contracts, oil production licences and oil mining leases (and related farm-in agreements), as applicable (the "Licences"), annual work programmes and budgets as set forth therein. The relevant legislation provides that fines may be imposed and a Licence may be suspended or terminated if a licence holder or party to the contract fails to comply with its obligations under such Licence or agreement, or fails to make timely payments of levies and taxes for the licenced activity, provide the required geological information or meet other reporting requirements.
In addition, the Group's subsidiaries, joint ventures and associates have obligations to develop the fields in accordance with the specific requirements under the applicable Licences, field development plans, laws and regulations. If they were to fail to satisfy such obligations with respect to a specific field, the Licence for that field may be suspended, revoked or terminated.
The relevant authorities can, and do from time to time, inspect the Group's compliance with its Licences and relevant laws. There can be no assurance that the views of the relevant government agencies regarding the development of the Group's fields or compliance with the terms of its Licences will coincide with the Group's views, which might lead to disagreements that cannot be resolved.
The suspension, revocation or termination of any of the Group's Licences, as well as any delays in the continuous development of or production at its fields caused by the issues detailed above may have a material adverse effect on the Group's business, financial condition and results of operations.
Each of Afren's and FHN's exploration and production licences have incorporated within them detailed work programmes which have to be fulfilled and normally within a specified timeframe. These may include seismic surveys to be performed, wells to be drilled, production to be attained, limits to production levels and construction matters.
Failure to comply with such obligations, whether inadvertent or otherwise, may lead to fines, penalties, restrictions and withdrawal of licences with consequent material adverse effects.
Afren's and FHN's operations are subject to laws and regulations relating to the protection of human health and safety and the environment. Failure, whether inadvertent or otherwise, by Afren and FHN to comply with applicable legal or regulatory requirements may give rise to significant liabilities. Afren's and FHN's health, safety and environment policy is to observe local and national, legal and regulatory requirements and generally to apply best practice where local legislation does not exist.
The terms of licences or permissions may include more stringent environmental and/or health and safety requirements. The obtaining of exploration, development or production licences and permits may become more difficult or be the subject of delay due to governmental, regional or local environmental consultation, approvals or other considerations or requirements.
Afren and, if the Acquisition completes, the Enlarged Group incurs, and expects to continue to incur, substantial capital and operating costs in order to comply with increasingly complex health, safety, environmental laws and regulations.
Although the costs of the measures taken to comply with environmental regulations have not had a material adverse effect on Afren's financial condition or results of operations to date, in the future, the costs of such measures and liabilities related to environmental damage caused by Afren may increase, adversely affecting Afren's operating results and financial condition. Unanticipated costs may be incurred in respect of the assumption of pre-completion environmental liabilities associated with OML 26. Should any such environmental liability arise, it could have a material adverse effect on the Enlarged Group's business, results of operations or financial condition.
These factors may lead to delayed or reduced exploration, development or production activity as well as to increased costs.
On 4 April 2011 Afren entered into a put option deed with COGIL (the "Initial Deed") that granted COGIL a right (but not the obligation) (the "Option") to sell up to 15,000,000 ordinary shares in the capital of FHN (the "Option Shares") to Afren at a price equal to US\$2.24 per Option Share in cash.
On 25 March 2013, Afren and COGIL entered into a deed of variation to the Initial Deed (the "Deed of Variation" and together with the Initial Deed, the "Agreement") to:
Completion of the Option is not subject to any other condition precedent.
COGIL exercised the Option (as modified by the terms of the Deed of Variation) in full on 25 March 2013. Afren has indicated to COGIL that, subject to receipt of the necessary Afren shareholder approval, it intends for the Option Shares to be acquired by Adcax Investments Limited as trustee for Afren (see paragraph 3 below).
If shareholder approval for the Acquisition is not obtained at the General Meeting, completion of the Option will not occur. In such circumstances, the Option will be deemed not to have been exercised and COGIL shall have no right to re-exercise the Option and Afren shall have no obligation to acquire any FHN shares from COGIL under the Agreement.
Each of the Initial Deed and the Deed of Variation are governed by the laws of England. The courts of England shall are given non-exclusive jurisdiction to settle any dispute that may arise out of or in connection with the Agreement.
As part of the original acquisition by COGIL of the FHN shares the subject of the Option in 2011, FCMB made available a US\$33 million term loan facility to COGIL to finance COGIL's acquisition of such shares (the "COGIL Loan"). The COGIL Loan was due to be repaid in April 2013, or on the earlier disposal by COGIL of the relevant FHN shares (including under the terms of the Option). Each of COGIL and FCMB anticipate that the COGIL Loan will be repaid from the proceeds of the sale of the Option Shares to Afren pursuant to the exercise of the Option by COGIL.
Under the terms of the Deed of Variation, the sale of the Option Shares by COGIL is now subject to receipt of Afren shareholder approval, whereas no such approval was required under the Initial Deed. Accordingly, FCMB was concerned that if Afren's shareholders did not approve the acquisition of the Option Shares, COGIL would not be able to sell the Option Shares and use the proceeds to repay the COGIL Loan and COGIL may therefore be in default of its repayment obligations when the COGIL Loan became due for repayment.
Therefore in order to provide assurances to FCMB as to the repayment of the COGIL Loan by COGIL in circumstances where, due to the lack of Afren shareholder approval to the Acquisition, COGIL is unable to complete the sale of the Option Shares to Afren under the Option, on 25 March 2013 Afren also entered into an agreement with FCMB and COGIL (the "Side Agreement") in respect of the acquisition by Afren of the COGIL Loan from FCMB in the event that shareholder approval for completion of the acquisition of the Option Shares is not received.
Pursuant to the Side Agreement, FCMB and COGIL have agreed to extend the date for repayment of the COGIL loan until October 2013 or on the earlier disposal by COGIL of the relevant FHN shares (including under the terms of the Option).
Pursuant to the Side Agreement Afren has agreed with FCMB that, if the Condition is not satisfied, it will purchase from FCMB all outstanding amounts due and payable by COGIL under the COGIL Loan. As a result, if shareholder approval for the Acquisition is not obtained, then following such loan purchase COGIL shall be obliged to repay such debt to Afren instead of FCMB. COGIL has agreed to grant security over the Option Shares in favour of Afren to secure such repayment obligation.
Under the Side Agreement, Afren will be entitled to purchase or seek purchasers for the Option Shares for a period of three months from the date of non-satisfaction of the Condition, failing which each of COGIL and Afren shall be entitled to seek purchasers for the Option Shares. Each of Afren and COGIL has agreed that the COGIL Loan will be repaid out of the proceeds of the sale of the Option Shares once completed, with the balance of any sale proceeds from the Option Shares being paid to Afren (if such shares are sold in the first three months following non-satisfaction of the Condition) or shared equally between Afren and COGIL (if such shares are sold following the expiry of such three month period). If the relevant FHN shares are not sold before the expiry of the term of the COGIL Loan in October 2013, COGIL shall be entitled to transfer the FHN shares to Afren (or as Afren directs) in full and final satisfaction of its payment obligations under the COGIL Loan.
If following its acquisition of the COGIL Loan Afren seeks repayment of the COGIL Loan, or the COGIL Loan becomes repayable upon any default under such loan, COGIL is entitled to transfer the Option Shares to Afren (or as Afren shall direct) in full and final satisfaction of the COGIL Loan. In such circumstances where neither Afren nor COGIL have been able to successfully seek purchasers for the Option Shares, Afren shall either (a) seek prior shareholder approval for the acquisition of the Option Shares and shall not acquire such shares pending receipt of such shareholder approval or (b) direct that the legal and beneficial interest in such shares be transferred to a third party or otherwise held by a third party in escrow (in circumstances where Afren has no interest in such shares).
In any event, for so long as the acquisition of the Option Shares requires the approval of the Company's shareholders in accordance with the provisions of Chapter 10 of the Listing Rules, Afren undertakes that it shall not acquire the legal or beneficial interest in such shares, whether under the Option, in repayment of the COGIL Loan or otherwise, unless it has previously obtained such shareholder approval.
The Side Agreement shall only become operative as regards Afren if the Condition is not satisfied. It does not need separate Afren shareholder approval.
The Side Agreement is governed by the laws of England (other than in respect of the extension of the term of the COGIL Loan, which is subject to Nigerian law). The courts of England have non-exclusive jurisdiction to settle any dispute that may arise out of or in connection with the Side Agreement.
To take advantage of the potential benefits of FHN remaining as an indigenous company in Nigeria, Afren's ownership in FHN will be structured in order to meet the criteria generally understood and sometimes required under Nigerian oil and gas industry policies for FHN to be classified as an indigenous Nigerian company, with the majority of its equity interest held by Nigerian owners (see "Indigenous company status in Nigeria" in paragraph 3 of Part 1 for further information on Nigerian indigenous status).
In order to do so, Afren intends to split its legal and beneficial holdings in FHN such that it is the legal owner of not more than 45% of the issued ordinary shares in FHN. The remaining portion of Afren's legal interest in FHN will be held in trust for the benefit of Afren by Adcax Investments Limited, a Nigerian-formed trust company (the "Trustee"). Accordingly, only the beneficial title to the Option Shares is proposed to be acquired by Afren, with the legal title being acquired by the Trustee while Afren will be the beneficiary of all the benefits accruing to the Option Shares.
The beneficiaries of the Trust Deed are Afren and such designated Nigerian employees of Afren as Afren may from time to time determine at its discretion. Following completion of the Acquisition, Afren may use these trust arrangements for the benefit of its Nigerian employees to become beneficiaries of FHN shares under the trust.
Afren's existing 44.5% interest in FHN is currently held as to approximately 41.9% by the Company through its subsidiary, Afren Nigeria Holdings Limited ("ANH"), and as to approximately 2.5% by the Trustee, which holds the legal title to such deferred shares on trust for ANH following their acquisition by ANH in February 2013 from certain members of management of FHN.
The trust arrangement with the Trustee was established to govern the Company's relationship with, and its rights and entitlements to, FHN and its Nigerian subsidiaries. In connection with the trust arrangements described above, the Company and the Trustee entered into a trust deed on 2 May 2013 (the "Trust Deed"). The Trustee is a company limited by shares organised under the laws of Nigeria and is wholly owned by the named members of Adepetun Caxton-Martins Agbor & Segun, a Nigerian law firm that routinely provides legal advisory and company secretarial services to the Group. The Trust Deed confers on the Trustee all typical powers of a trustee to hold the Trust Shares and act as trustee of the Trust.
Pursuant to this Trust Deed, all of the Option Shares (representing approximately 10.4% of the outstanding share capital of FHN) shall be legally owned, and held in trust initially for the Company's benefit, by the Trustee. In particular, to address the Company's rights and provide that it has the full benefit of indigenous status, the Trust Deed provides that:
The Company, at its discretion, may terminate the Trust Deed at any time and/or require the Trustee to deliver legal title to the Option Shares to Afren (or as Afren may nominate).
The Company has agreed to indemnify the Trustee and its officers and managers (each an "Indemnified Person") against all costs and liabilities that any of them may suffer or incur in relation to the execution of the powers and trusts contained in the Trust Deed and otherwise by virtue of the Trustee being the trustee of the Trust Shares other than in the event of wilful default, negligence or fraud by an Indemnified Person under the Trust.
The Trust Deed is governed by the laws of Nigeria and any disputes arising out of, or in connection with, the Trust Deed shall be settled pursuant to the rules for arbitration proceedings contained in Nigeria's Arbitration and Conciliation Act Cap A18 Laws of the Federation of Nigeria 2004.
This trust arrangement does not need separate Afren shareholder approval, as it does not amount to a Class 1 transaction based on the class tests, and the Company does not intend to seek shareholder approval on a voluntary basis for the performance of its obligations under the Trust Deed.
The Board of Directors on behalf of Afren plc Kinnaird House 1 Pall Mall East London SW1Y 5AU
Merrill Lynch International 2 King Edward Street London EC1A 1HQ
2 May 2013
Dear Sirs,
We report on the financial information for the period from 25 June 2009 to 31 December 2010, the year ended 31 December 2011 and the year ended 31 December 2012, as set out in Part 5 of the Class 1 Circular relating to the acquisition of Target dated 2 May 2013 of Afren plc (the "Company" and, together with its subsidiaries, the "Group") (the "Circular"). This financial information has been prepared for inclusion in the Circular on the basis of the accounting policies set out in note 2 to the financial information. This report is required by Listing Rule 13.5.21R and is given for the purpose of complying with that requirement and for no other purpose.
The Directors of the Company are responsible for preparing the financial information in accordance with International Financial Reporting Standards as adopted by the European Union.
It is our responsibility to form an opinion on the financial information and to report our opinion to you.
Save for any responsibility which we may have to those persons to whom this report is expressly addressed and which we may have to Ordinary shareholders as a result of the inclusion of this report in the Circular, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with Listing Rule 13.4.1R(6), consenting to its inclusion in the Circular.
We conducted our work in accordance with Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. Our work included an assessment of evidence relevant to the amounts and disclosures in the financial information. It also included an assessment of significant estimates and judgments made by those responsible for the preparation of the financial information and whether the accounting policies are appropriate to the entity's circumstances, consistently applied and adequately disclosed.
We planned and performed our work so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the financial information is free from material misstatement whether caused by fraud or other irregularity or error.
Our work has not been carried out in accordance with auditing or other standards and practices generally accepted in jurisdictions outside the United Kingdom, including the United States of America, and accordingly should not be relied upon as if it had been carried out in accordance with those standards and practices.
In our opinion, the financial information gives, for the purposes of the Circular, a true and fair view of the state of affairs of the Target Group as at 31 December 2010, 2011 and 2012 and of its profits, cash flows and changes in equity for the period from 25 June 2009 to 31 December 2010, the year ended 31 December 2011, and the year ended 31 December 2012 in accordance with International Financial Reporting Standards as adopted by the European Union and has been prepared in a form that is consistent with the accounting policies adopted in the Company's latest annual accounts.
Yours faithfully
Chartered Accountants
Deloitte LLP is a limited liability partnership registered in England and Wales with registered number OC303675 and its registered office at 2 New Street Square, London EC4A 3BZ, United Kingdom. Deloitte LLP is the United Kingdom member firm of Deloitte Touche Tohmatsu Limited ("DTTL"), a UK private company limited by guarantee, whose member firms are legally separate and independent entities. Please see www.deloitte.co.uk/about for a detailed description of the legal structure of DTTL and its member firms. Note: references in this Part 5 to (i) "Group" are references to FHN and its consolidated subsiary undertakings only and (ii) "Management" are references to the management of FHN only.
| 2012 | 2011 | 2010 | ||
|---|---|---|---|---|
| Notes | US\$000's | US\$000's | US\$000's | |
| Revenue | 5 | 112,366 | – | – |
| Cost of sales | 6 | (70,813) | 6,788 | – |
| Gross profit | 41,553 | 6,788 | – | |
| Administrative expenses | –––––––– (24,557) |
–––––––– (12,979) |
–––––––– (5,507) |
|
| Other operating expenses | ||||
| – derivative financial instruments | 16 | (29,060) –––––––– |
(12,342) –––––––– |
– –––––––– |
| Operating loss | (12,064) | (18,533) | (5,507) | |
| Finance income | 5,8 | 1,111 | 366 | 5 |
| Finance costs | 8 | (18,580) | (2,184) | (27) |
| Other gains and (losses) | ||||
| – foreign currency gains/(losses) | (447) –––––––– |
436 –––––––– |
(1,290) –––––––– |
|
| Loss from continuing operations before tax | (29,980) | (19,915) | (6,819) | |
| Income tax credit | 21 | 7,265 | 13,437 | – |
| Loss from continuing operations after tax | –––––––– (22,715) |
–––––––– (6,478) |
–––––––– (6,819) |
|
| –––––––– | –––––––– | –––––––– |
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Loss after tax | (22,715) | (6,478) | (6,819) |
| Total comprehensive income attributable to equity holders | –––––––– (22,715) |
–––––––– (6,478) |
–––––––– (6,819) |
| –––––––– | –––––––– | –––––––– |
| Notes US\$000's US\$000's US\$000's Assets Non-current assets Goodwill 9 115,185 115,185 – Property, plant and equipment – Oil and gas assets 10 149,684 151,067 – – Other 11 401 587 – –––––––– –––––––– –––––––– 265,270 266,839 – –––––––– –––––––– –––––––– Current assets Trade and other receivables 13 46,993 13,448 29,145 Cash and cash equivalents 14 73,929 62,226 10,456 –––––––– –––––––– –––––––– 120,922 75,674 39,601 –––––––– –––––––– –––––––– Total assets 386,192 342,513 39,601 –––––––– –––––––– –––––––– Liabilities Current liabilities Trade and other payables 15 (55,191) (8,699) Borrowings 16 (28,109) (7,987) – Derivative financial instruments 16 (17,273) (7,636) – –––––––– –––––––– –––––––– (100,573) (24,322) –––––––– –––––––– –––––––– Net current assets 20,349 51,352 38,269 –––––––– –––––––– –––––––– Non-current liabilities Other payables 15 (1,885) (1,885) Provision for decommissioning 17 (2,637) (2,502) – Deferred tax liabilities 19 (93,676) (101,748) – Borrowings 16 (119,726) (138,841) – Derivative financial instruments 16 (8,377) (4,706) – –––––––– –––––––– –––––––– (226,301) (249,682) –––––––– –––––––– –––––––– Total liabilities (326,874) (274,004) –––––––– –––––––– –––––––– Net assets 59,318 68,509 34,134 –––––––– –––––––– –––––––– Equity Share capital 20 (839) (871) (774) Share premium 20 (67,271) (65,757) (40,179) Other reserves 25 (27,220) (15,178) – Retained earnings 36,012 13,297 6,819 –––––––– –––––––– –––––––– Total equity (59,318) (68,509) –––––––– –––––––– –––––––– |
2012 | 2011 | 2010 | |
|---|---|---|---|---|
| (1,332) | ||||
| (1,332) | ||||
| (4,135) | ||||
| (4,135) | ||||
| (5,467) | ||||
| (34,134) |
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Notes | US\$000's | US\$000's | US\$000's |
| Operating loss for the period | (12,064) | (18,533) | (5,507) |
| Depreciation, depletion and amortisation | 5,706 | 1,696 | – |
| Derivative financial instruments | 13,308 | 12,342 | – |
| Share-based payments charge 7 |
12,042 –––––––– |
101 –––––––– |
– –––––––– |
| Operating cash-flows before movements | |||
| in working capital | 18,992 | (4,394) | (5,507) |
| Increase in trade and other operating receivables | (20,644) | (12,828) | – |
| Increase in trade and other operating payables | 45,685 | 11,868 | 5,214 |
| Net cash generated/(used) in operating activities | –––––––– 44,033 |
–––––––– (5,354) |
–––––––– (293) |
| Purchases of property, plant and equipment: | –––––––– | –––––––– | –––––––– |
| – oil and gas assets | (4,823) | (135,012) | – |
| – other | (120) | (780) | – |
| Expenditure on acquisitions pending completion | (6,000) | – | (12,500) |
| Net cash used in investing activities | –––––––– (10,943) |
–––––––– (135,792) |
–––––––– (12,500) |
| Issue of ordinary share capital | –––––––– 1,737 |
–––––––– 43,934 |
–––––––– 24,560 |
| Costs of share issues | – | (475) | – |
| Proceeds from borrowings | – | 158,000 | – |
| Borrowing costs | – | (8,931) | – |
| Repayment of borrowings | (16,647) | – | – |
| Issue of borrowings | (6,000) | – | – |
| Interest received | 211 | 366 | 5 |
| Interest and financing fees paid | (238) –––––––– |
(243) –––––––– |
(27) –––––––– |
| Net cash (used in)/provided by financing activities | (20,937) | 192,651 | 24,538 |
| Net increase in cash and cash equivalents | –––––––– 12,153 |
–––––––– 51,505 |
–––––––– 11,745 |
| Cash and cash equivalents at beginning of period | 62,226 | 10,456 | – |
| Effect of foreign exchange rate changes | (450) –––––––– |
265 –––––––– |
(1,289) –––––––– |
| Cash and cash equivalents at end of period 14 |
73,929 | 62,226 | 10,456 |
–––––––– –––––––– ––––––––
For the years ended 31 December 2012 and 31 December 2011, and the period from 25 June 2009 to 31 December 2010
| Share | |||||
|---|---|---|---|---|---|
| Share | premium | Other Accumulated | Total | ||
| capital | account | reserves | losses | equity | |
| US\$000's | US\$000's | US\$000's | US\$000's | US\$000's | |
| Group | |||||
| At incorporation on | |||||
| 25 June 2009 | – | – | – | – | – |
| Issue of share capital | 774 | 15,711 | – | – | 16,485 |
| Shares transferred at premium | – | 24,468 | – | – | 24,468 |
| Total comprehensive income | |||||
| for the period | – | – | – | (6,819) | (6,819) |
| Balance at 31 December | –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
| 2010 | 774 | 40,179 | – | (6,819) | 34,134 |
| Issue of share capital | –––––––– 97 |
–––––––– 18,872 |
–––––––– – |
–––––––– – |
–––––––– 18,969 |
| Shares transferred at premium | – | 6,706 | – | – | 6,706 |
| Share-based payments, | |||||
| call options | – | – | 10,905 | – | 10,905 |
| Share-based payments, services | – | – | 101 | – | 101 |
| Convertible loan issued, | |||||
| equity component | – | – | 4,172 | – | 4,172 |
| Total comprehensive income | |||||
| for the year | – | – | – | (6,478) | (6,478) |
| Balance at 31 December | –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
| 2011 | 871 | 65,757 | 15,178 | (13,297) | 68,509 |
| Shares transferred at premium | –––––––– – |
–––––––– 1,514 |
–––––––– – |
–––––––– – |
–––––––– 1,514 |
| Cancellation of shares | (32) | – | – | – | (32) |
| Share-based payments, services | – | – | 12,042 | – | 12,042 |
| Total comprehensive income | |||||
| for the year | – | – | – | (22,715) | (22,715) |
| Balance at 31 December | –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
| 2012 | 839 –––––––– |
67,271 –––––––– |
27,220 –––––––– |
(36,012) –––––––– |
59,318 –––––––– |
First Hydrocarbon Nigeria Company Limited (the Company, and together with its subsidiaries, the Group) was incorporated in Nigeria on 25 June 2009. The principal activity of the Company and its subsidiary undertakings is the exploration for and development and production of oil and gas in Nigeria.
The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union and are presented for the period from 25 June 2009 to 31 December 2010, and years ended 31 December 2011 and 31 December 2012, being the period up to the end of the latest financial year for which First Hydrocarbon Nigeria has prepared audited accounts. The financial statements have been prepared on the historical cost basis, except for the revaluation of certain financial instruments that have been measured at fair value.
The Group financial information consolidates that of the Company and of its subsidiary undertakings drawn up to 31 December each year. The results of subsidiaries acquired in the period are included in the income statement from the date that control is transferred to the Group. Control exists when the Company has the power, directly or indirectly, to govern the financial and operating policies of an entity so as to obtain benefits from its activities.
The results of subsidiaries acquired or disposed of during the period are included in the consolidated income statement from the effective date of acquisition or up to the effective date of disposal as appropriate. All intra-Group transactions, balances, income and expenses are eliminated on consolidation.
Acquisitions of subsidiaries and businesses, including jointly controlled interests in such businesses, are accounted for using the acquisition method. The consideration for each acquisition is measured at the aggregate of the fair values (at the date of exchange) of assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree. Acquisition-related costs are recognised in profit or loss as incurred.
The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognised at their fair value at the acquisition date, except that:
If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see below), or additional assets or liabilities are recognised, to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date.
The measurement period is the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as of the acquisition date, and is subject to a maximum of one year.
Goodwill arising in a business combination is recognised as an asset at the date that control is acquired. Goodwill is measured as the excess of the sum of the consideration transferred, the amount of any non-controlling interest in the acquiree and the fair value of the acquirer's previously held equity interest (if any) in the entity over the net of the acquisition-date amounts of the identifiable assets acquired and the liabilities assumed.
The Group is engaged in oil and gas exploration, development and production through unincorporated joint ventures. The Group accounts for its share of the results and net assets of these joint ventures as jointly controlled assets.
Property, plant and equipment are stated at cost less depreciation and any provision for impairment.
Depreciation is provided at rates calculated to write off the cost of the tangible fixed assets, less anticipated disposal proceeds, on a straight-line basis over their estimated useful economic life as follows:
| Leasehold improvements | over life of lease |
|---|---|
| Fixtures and equipment | over three years |
| Computer hardware and software | over three years |
| Motor vehicles | over three years |
The Group follows the successful efforts method of accounting for intangible exploration and evaluation costs. All licence acquisition, exploration and evaluation costs are initially capitalised as intangible fixed assets in cost centres by field or exploration area, as appropriate, pending determination of commerciality of the relevant property. Directly attributable administration costs are capitalised insofar as they relate to specific exploration activities. Pre-licence costs and general exploration costs not specific to any particular licence or prospect are expensed as incurred.
If prospects are deemed to be impaired ('unsuccessful') on completion of the evaluation, the associated costs are charged to the income statement. If the field is determined to be commercially viable, the attributable costs are transferred to property, plant and equipment in single field cost centres. These costs are then depreciated on a unit of production basis.
All field development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities are amortised in accordance with the Group's depletion and amortisation accounting policy.
Revenue represents the sales of crude oil, net of taxes and royalties paid in kind or where the financial obligation does not fall directly to the Company, of the Group's share of oil liftings in the period. Oil revenue is recognised when goods are delivered and title has passed. Interest income is accrued on a time basis by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount.
Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable reserves and a 50% statistical probability that it will be less.
All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field-by-field basis. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively.
Where there has been a change in economic conditions that indicates a possible impairment in a discovery field, the recoverability of the net book value relating to that field is assessed by comparison with the estimated discounted future cash flows based on Management's expectations of future oil and gas prices and future costs. Any impairment identified is charged to the income statement as additional depletion and amortisation. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any depreciation that would have been charged since the impairment.
Provision for decommissioning is recognised in full when the related facilities are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each period in accordance with local conditions and requirements.
Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning is included as a finance cost.
Non-current assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such triggering events are defined in IFRS 6 in respect of intangible exploration and evaluation assets and include the point at which determination is made as to whether commercial reserves exist.
Where there has been an indication of a possible impairment, Management assesses the recoverability of the carrying value of the asset by comparison with the estimated discounted future net cash flows based on Management's expectation of future production, oil prices and costs. Any identified impairment is charged to the income statement.
The individual financial statements of each Group company are presented in the currency of the primary economic environment in which it operates (its functional currency). For the purpose of consolidated financial statements, the results and financial position of each Group company are expressed in US dollars which is the functional currency of the Company and the presentational currency for the consolidated financial statements of the Group.
The tax expense represents the sum of tax currently payable and deferred tax.
The tax currently payable is based on taxable profit for the period in accordance with the Petroleum Profits Tax Act, CAP P13, LFN 2004. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences, the principal exception being that no deferred tax is recorded in respect of goodwill, and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available to allow all or part of the assets to be recovered.
Deferred tax is calculated at the rates of tax expected to apply in the period when the liability is settled or the asset realised.
The Group makes equity-settled share-based payments to certain employees, Directors and other third parties. Equity-settled share-based schemes are measured at fair value (excluding the effect of non market-based vesting conditions) at the date of grant, measured by use of an appropriate valuation model. The expected life used in the model has been adjusted, based on Management's best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.
The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the period to exercise, based on the Group's estimate of shares that will eventually vest.
Lifting or offtake arrangements for oil produced in the Group's jointly owned operations are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production is 'underlift' or 'overlift'. Underlift and overlift are valued at market value and included within debtors and creditors respectively. Movements during an accounting period are adjusted through cost of sales such that gross profit is recognized on an entitlements basis.
Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.
Financial costs of debt are allocated to periods over the term of the related debt at a constant rate on the carrying amount. Arrangement fees and issue costs are deducted from the debt proceeds on initial recognition of the liability and are amortised and charged to the income statement as finance costs over the term of the debt.
All other borrowing costs are recognised in profit or loss in the period in which they are incurred.
Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes party to the contractual provisions of the instrument.
The Group entered into a number of deferred put options in respect of production from the OML 26 field. The instruments are stated at fair value and have been classified as cash flow hedges. Each period the portion of the gains and losses on the hedging instruments that is determined to be an effective hedge is taken to equity and the ineffective portion, as well as any change in time value, is recognised in the income statement.
Trade receivables are measured at initial recognition at their fair value. Appropriate allowances for estimated irrecoverable amounts are recognised in the income statement when there is objective evidence that the asset is impaired.
Cash and cash equivalents comprise cash on hand, demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of change in value.
Trade payables are stated at amortised cost.
Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Company are recorded at the proceeds received net of direct issue costs.
Convertible loan notes are regarded as compound instruments consisting of a liability component and an equity component. At the date of issue, the fair value of the liability component is estimated using the prevailing market interest rate for similar non-convertible debt. The difference between the proceeds of issue of the convertible loan notes and the fair value assigned to the liability component represents the embedded option to convert the liability into equity of the Group and is included in equity. Issue costs are apportioned between the liability and equity components of the convertible loan notes based on their relative carrying amounts at the date of issue. The portion relating to the equity is charged directly against equity. The interest expense on the liability component is calculated based on the effective interest rate and the recognised in the income statement.
A number of new standards, amendments to standards and interpretations are effective for annual periods beginning after 1 January 2013, and have not been applied in preparing these financial statements. None of these are expected to have a significant effect on the financial statements. There are other standards in existence which will be considered once endorsed for use in the EU.
In the application of the Group's accounting policies, which are described in Note 2, the Directors are required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both current and future periods. The following are the critical judgements, key assumptions and other key sources of estimation uncertainty at the balance sheet date that may have a significant effect on the amounts recognised in the financial statements.
Management is required to assess the oil and gas assets for indicators of impairment, and test goodwill for impairment annually. The carrying value of tangible oil and gas assets are disclosed in Note 10, and carrying amount of goodwill is disclosed in Note 9. As part of this assessment, the carrying value of the assets at the balance sheet date is compared with the expected discounted cash flows from each project. Management judgement is required in the calculation of the fair value of these cash flows.
Management is required to make assumptions in respect of the inputs used to calculate the fair value of share-based payments. Details of these can be found in Note 23.
The assets and liabilities acquired following the completion of OML 26 licence acquisition by the Group in 2011 were recorded at fair value at the completion date, as outlined further in Note 24. The estimates of such fair values required significant judgement to be applied. Management has used a production profile based on its best estimate of proven and probable reserves of the assets and a range of assumptions, including an internal oil price profile benchmarked to mean analysts' consensus and a 14% discount rate which, taking into account other assumptions used in the calculation, Management considers being reflective of the risks.
As disclosed in Note 13, the Group provided a US\$6.0 million loan to EER (Colobus) Nigeria Limited to assist that company in meeting its obligation in respect of the OML 113 licence acquisition deposit. The loan is repayable on the 14th of October 2013. The Directors are of the view that the loan agreement provides sufficient security over the loan and that it will be recovered in full in October 2013.
The Group has decommissioning obligations in respect of the OML 26 licence. The extent to which a provision is required depends on the legal requirements at the date of decommissioning, the costs and timing of work and the discount rate to be applied. The decommissioning provision will be updated each period to reflect Management's best estimates. A corresponding amount equivalent to the provision is recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each period in accordance with local conditions and requirements, reflecting Management's best estimates. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning is included as a finance cost.
The application of tax legislation in jurisdictions in which the Group operates can be uncertain and subject to interpretation. The Group calculates the tax charge for each period using the latest information available, taking external advice where necessary, in order to arrive at the best estimate of the final tax position. Revisions to tax liabilities (either upward or downward) may occur as the Group's tax filings and royalties are agreed with the relevant authorities in future periods.
Note 16 of this consolidated financial information includes the Group's objectives, policies and processes for managing capital and its exposure to credit and liquidity risk.
The directors have a reasonable expectation that the Group have adequate resources to continue in operation for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing this consolidated financial information.
The Group operates in one geographical segment, being Nigeria.
The operations of the Group comprise one class of business, being oil and gas exploration, development and production.
| 2012 US\$000's |
2011 US\$000's |
2010 US\$000's |
|
|---|---|---|---|
| Sale of oil | 112,366 | – | – |
| Finance income (Note 8) | 1,111 –––––––– |
366 –––––––– |
5 –––––––– |
| 113,477 | 366 | 5 | |
| –––––––– | –––––––– | –––––––– |
Oil revenue is derived from sales under an off-take agreement with a single customer.
As set out in Note 2, underlift and overlift recognised in the period is adjusted through costs of sales such that the gross profit is recognised on an entitlements basis. For the year ended 31 December 2011, an underlift credit of US\$11.3 million was credited to cost of sales, resulting in a final cost of sales credit balance of US\$6.8 million. For the year ended 31 December 2012, an overlift expense amounting to US\$26.1 million has been recognised in cost of sales.
The average monthly number of employees (including Executive Directors) employed was as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Management | 4 | 2 | 2 |
| Administration | 12 | 8 | – |
| –––––––– 16 |
–––––––– 10 |
–––––––– 2 |
|
| Their aggregate remuneration comprised: | –––––––– | –––––––– | –––––––– |
| 2012 | 2011 | 2010 | |
| US\$000's | US\$000's | US\$000's | |
| Wages and salaries | 3,558 | 2,079 | 60 |
| Share-based payments | 12,042 | 101 | – |
| Social security costs | 43 | 19 | – |
| Pension costs | 258 | 62 | – |
| –––––––– 15,901 –––––––– |
–––––––– 2,261 –––––––– |
–––––––– 60 –––––––– |
|
| 8. Finance income and expense |
|||
| 2012 | 2011 | 2010 | |
| US\$000's | US\$000's | US\$000's | |
| Finance income | |||
| Bank interest | 1,111 | 366 | 5 |
| –––––––– | –––––––– | –––––––– |
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Finance expense | |||
| Bank interest and charges | 238 | 243 | 27 |
| Borrowing costs amortisation and facility fees | 2,037 | 273 | – |
| Interest on finance facility | 9,769 | 1,237 | – |
| Unwinding of discount on convertible loan notes (Note 18) | 6,401 | 421 | – |
| Unwinding of discount on decommissioning | |||
| provision (Note 17) | 135 | 10 | – |
| –––––––– 18,580 |
–––––––– 2,184 |
–––––––– 27 |
|
| –––––––– | –––––––– | –––––––– |
| Total | |
|---|---|
| US\$000's | |
| Cost and carrying amount | |
| At incorporation on 25 June 2009 | – –––––––– |
| At 1 January 2011 | – |
| Acquisition of OML 26 | 115,185 –––––––– |
| At 1 January 2012 | 115,185 |
| At 31 December 2012 | –––––––– 115,185 |
Goodwill held at the years ended 31 December 2011 and 2012 relates solely to OML 26, which is considered a cash generating unit (CGU).
––––––––
The recoverable amount of the CGU is determined based on the higher of value-in-use calculations using cash flow projections and fair value less costs to sell if appropriate. For the discounted cash flows to be calculated, Management has used a production profile based on its best estimate of proven and probable reserves of the assets and a range of assumptions, including an internal oil price profile benchmarked to mean analysts' consensus and a 14% pre-tax discount rate which, taking into account other assumptions used in the calculation, Management considers to be reflective of the risks.
| Total | |
|---|---|
| US\$000's | |
| Oil and gas assets | |
| Cost | |
| At incorporation on 25 June 2009 | – |
| At 1 January 2011 | –––––––– – |
| Acquisition of OML 26 | 149,992 |
| Additions | 2,578 |
| At 1 January 2012 | –––––––– 152,570 |
| Additions | 4,018 –––––––– |
| At 31 December 2012 | 156,588 |
| –––––––– |
| Total US\$000's |
|
|---|---|
| Depletion, depreciation and amortisation At incorporation on 25 June 2009 |
– |
| At 1 January 2011 | – |
| Charge for the year | 1,503 |
| At 1 January 2012 | –––––––– 1,503 |
| Charge for the year | 5,401 |
| At 31 December 2012 | –––––––– 6,904 |
| Carrying amount | –––––––– |
| At 31 December 2010 | – |
| At 31 December 2011 | –––––––– 151,067 |
| At 31 December 2012 | –––––––– 149,684 |
–––––––– Oil and gas assets relate to solely to the production asset OML 26 and include the fair value assigned on acquisition. Refer to Note 24 for additional information on the acquisition on OML 26.
| improvements US\$000's |
Leasehold Fixtures and US\$000's |
Computer hardware equipment and software |
Motor vehicles US\$000's US\$000's |
Total US\$000's |
|
|---|---|---|---|---|---|
| Other property, plant and equipment Cost |
|||||
| At incorporation on 25 June 2009 | – –––––––– |
– –––––––– |
– | – –––––––– –––––––– |
– –––––––– |
| At 1 January 2011 | – | – | – | – | – |
| Additions | 289 –––––––– |
191 –––––––– |
2 | 298 –––––––– –––––––– |
780 –––––––– |
| At 1 January 2012 | 289 | 191 | 2 | 298 | 780 |
| Additions | 7 –––––––– |
77 –––––––– |
10 | 26 –––––––– –––––––– |
120 –––––––– |
| At 31 December 2012 | 296 –––––––– |
268 –––––––– |
12 | 324 –––––––– –––––––– |
900 –––––––– |
| Accumulated depreciation At incorporation on 25 June 2009 |
– –––––––– |
– –––––––– |
– | – –––––––– –––––––– |
– –––––––– |
| At 1 January 2011 | – | – | – | – | – |
| Charge for the year | 88 –––––––– |
35 –––––––– |
– | 70 –––––––– –––––––– |
193 –––––––– |
| At 1 January 2012 | 88 | 35 | – | 70 | 193 |
| Charge for the year | 138 –––––––– |
56 –––––––– |
8 | 104 –––––––– –––––––– |
306 –––––––– |
| At 31 December 2012 | 226 –––––––– |
91 –––––––– |
8 | 174 –––––––– –––––––– |
499 –––––––– |
| Carrying amount At 31 December 2010 |
– –––––––– |
– –––––––– |
– | – –––––––– –––––––– |
– –––––––– |
| At 31 December 2011 | 201 | 156 | 2 | 228 | 587 |
| At 31 December 2012 | –––––––– 70 –––––––– |
–––––––– 177 –––––––– |
4 | –––––––– –––––––– 150 –––––––– –––––––– |
–––––––– 401 –––––––– |
A list of the significant subsidiaries, including the name, proportion of ownership interest, country of operation and country of registration, is given below:
| Country of | Country of | |||
|---|---|---|---|---|
| Name | Principal activity | % | operation registration | |
| Directly held | ||||
| FHN 26 Limited | Oil and gas exploration, development and production 100 | Nigeria | Nigeria | |
| FHN 113 Limited | Oil and gas exploration, development and production 100 | Nigeria | Nigeria | |
| FHN Energy | ||||
| Services Limited | Oil and gas exploration, development and production 100 | Nigeria | Nigeria | |
| FHN Ofa Limited | Oil and gas exploration, development and production 100 | Nigeria | Nigeria | |
| FHN 310 Limited | Oil and gas exploration, development and production 100 | Nigeria | Nigeria | |
| FHN Gas Limited | Oil and gas exploration, development and production 100 | Nigeria | Nigeria | |
| 13. | Trade and other receivables | |||
| 2012 | 2011 | 2010 | ||
| US\$000's | US\$000's | US\$000's | ||
| Trade and other debtors | 12,779 | 98 | – | |
| Underlift receivable | – | 11,313 | – | |
| Prepayments and accrued income | 8,719 | 203 | 14,750 | |
| 6,900 | – | – |
|---|---|---|
| – | 620 | 14,395 |
| 148 | – | – |
| 18,447 | 1,214 | – |
| –––––––– 29,145 |
||
| –––––––– | –––––––– 46,993 13,448 |
The prepayment at 31 December 2010 represents an initial 10% acquisition deposit in relation to OML 26. This amount was subsequently transferred to oil and gas assets on completion of the acquisition in December 2011.
–––––––– –––––––– ––––––––
Prepayments at 31 December 2012 include an acquisition deposit amounting to US\$6.0 million in relation to the Group acquiring an interest in the OML 113 licence. Completion of the acquisition is expected to occur in 2013, at which time this amount will be transferred to oil and gas assets. Refer to Note 24 for additional information.
In 2012, the Group provided a US\$ 6.0 million loan to EER (Colobus) Nigeria Limited to assist that company in meeting its obligation in respect of the OML 113 licence acquisition deposit. The loan was originally repayable on the 28th of March 2013 and attracted interest at 20% per annum. Subsequent to 31 December 2012, the acquisition completion date has been extended until September 2013. As a result of the completion date extension, the repayment date of the loan has been extended to 14 October 2013. Interest payable under the extended repayment term is at 25% per annum.
There were no material past due not impaired receivables at either balance sheet dates, nor any material bad debt provisions.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Cash and cash equivalents | 52,946 | 51,250 | 10,456 |
| Restricted cash – held on deposit | 10,976 | 10,976 | – |
| Restricted cash – lien on letter of credit | 10,007 –––––––– |
– –––––––– |
– –––––––– |
| 73,929 | 62,226 | 10,456 | |
| –––––––– | –––––––– | –––––––– |
Cash and cash equivalents comprise cash held by the Group in the form of short-term bank deposits with an original maturity of three months or less and earn interest at respective short-term deposit rates. The carrying amount of these assets approximates their fair value.
The restricted cash held on deposit represents cash restricted for debt service on certain third party loans, whereby under the terms of the loan agreements the Group is required to restrict funds to provide a cash buffer if cash available for debt service is less than payments due.
The Group provided a letter of credit in favour of Nigeria Petroleum Development Company Limited for US\$20 million. The letter of credit required the Group to restrict US\$10 million to provide guarantee for any default with respect to cash calls made by Nigeria Petroleum Development Company Limited. The letter of credit covers the Group's obligations under the Joint Operating Agreement for OML26.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Current | |||
| Trade creditors | 131 | 337 | – |
| Other creditors and operating partners | 7,923 | 3,541 | 1,313 |
| Overlift payable | 14,837 | – | – |
| Royalty payable | 3,421 | 2,319 | – |
| Accruals | 27,833 | 1,640 | 15 |
| Corporation tax payable | 807 | – | – |
| Other taxes | 239 | 862 | 4 |
| –––––––– 55,191 |
–––––––– 8,699 |
–––––––– 1,332 |
|
| Non-current | –––––––– | –––––––– | –––––––– |
| Other payables | 1,885 | 1,885 | 4,135 |
| –––––––– 1,885 |
–––––––– 1,885 |
–––––––– 4,135 |
–––––––– –––––––– –––––––– Non-current other payables relate to amounts owed to Afren Nigeria Holdings Ltd, a shareholder in the Group. The payable bears no interest.
| 2012 —————–———— |
2011 —————–———— |
2010 —————–———— |
||||
|---|---|---|---|---|---|---|
| US\$000's | Current Non-current US\$000's |
US\$000's | Current Non-current US\$000's |
US\$000's | Current Non-current US\$000's |
|
| Convertible loan notes | ||||||
| (Note 18) | – | 52,014 | – | 45,499 | – | – |
| Loan facility | 28,109 –––––––– |
67,712 –––––––– |
7,987 –––––––– |
93,342 –––––––– |
– –––––––– |
– –––––––– |
| 28,109 –––––––– |
119,726 –––––––– |
7,987 –––––––– |
138,841 –––––––– |
– –––––––– |
– –––––––– |
On 19 September 2011, the Group issued a six year US\$50 million senior unsecured unsubordinated convertible notes to fund the development activities of the Group. The convertible loan notes were subsequently fully subscribed to by Pan African Investment Partners II who hold the option to convert this to approximately 27 million shares at a conversion price of US\$1.85 per share. The loan notes can be converted to shares in the Group at any time from the date of issue until maturity (2017) in minimum tranches of \$5 million. The Group can from the fourth year after issuance redeem the loan notes at any time until maturity (2017) at an amount equal to the par value of the notes together with interest and a further interest payment of 20% per annum on the principle amount of the notes redeemed. If not previously repaid or redeemed, the Notes will be redeemed by the Group at maturity (2017) at a premium of 200% of the par value of the notes. The coupon interest rate associated with the loan notes is 0.15% per annum. The net proceeds from the issue of the loan notes were split between a liability component and an equity component at the date of issue. On issue, the liability component of the loan notes was US\$45.8 million, with the equity component being US\$4.2 million, before issue costs.
On 11 November 2011, the Group entered into a US\$230m loan facility with FCB Capital Markets Limited and Stanbic IBTC Bank PLC. The facility has an acquisition element (Tranche A) and a development element (Tranche B), both in respect of funding the acquisition and development of OML 26. The facility is for a five year term and interest on the facility is based on LIBOR plus 8.5%. In the year ended 31 December 2011, the Group drew down US\$108 million (Tranche A) to fund the completion of the OML 26 acquisition. The loan facility is repayable in quarterly tranches commencing December 2012 with full repayment by September 2016.
In respect of financial risk management, the Group manages liquidity risk by ensuring that sufficient funds are available to meet its commitments as they fall due.
The Group uses both short-term and long-term cash flow projections to monitor funding requirements and ensure there are sufficient cash resources to meet operational needs, taking into consideration the Group's debt financing plans. The following table details the Group's remaining contractual maturity for its non-derivative financial liabilities with agreed maturity periods. The table has been drawn based on the undiscounted cash flows of the financial liabilities based on the earliest date on which the Group can be required to pay, including interest payments.
| Weighted average effective interest % |
Less than 1 year US\$000's |
1-2 years US\$000's |
2-5 years US\$000's |
5+ years US\$000's |
Total US\$000's |
|---|---|---|---|---|---|
| 14.00% | – | – | 100,000 | – | 100,000 |
| 9.25% | 35,429 | 32,932 | 51,621 | – | 119,982 –––––––– |
| 35,429 | 32,932 | 151,621 | – | 219,982 | |
| –––––––– | |||||
| 14.00% | – | – | – | 100,000 | 100,000 |
| 9.25% | 16,740 | 35,429 | 84,552 | – | 136,721 –––––––– |
| 16,740 | 35,429 | 84,552 | 100,000 | 236,721 –––––––– |
|
| –––––––– –––––––– –––––––– –––––––– |
–––––––– –––––––– –––––––– |
–––––––– –––––––– –––––––– |
–––––––– –––––––– –––––––– –––––––– –––––––– –––––––– |
The amounts reported in the balance sheet relating to borrowings (excluding interest and debt costs) mature as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Due within one year | 27,000 | 6,750 | – |
| Due within two to five years | 126,835 | 147,435 | – |
| –––––––– 153,835 |
–––––––– 154,185 |
–––––––– – |
|
| Unamortised debt issue costs | (7,110) | (8,594) | – |
| Interest payable | 1,110 | 1,237 | – |
| –––––––– 147,835 |
–––––––– 146,828 |
–––––––– – |
|
| –––––––– | –––––––– | –––––––– |
| 2012 —————–———— |
2011 —————–———— |
2010 —————–———— |
|||||
|---|---|---|---|---|---|---|---|
| US\$000's | Current Non-current US\$000's |
US\$000's | Current Non-current US\$000's |
US\$000's | Current Non-current US\$000's |
||
| Deferred premium put options | 17,273 | 8,377 | 7,636 | 4,706 | – | – | |
| –––––––– 17,273 |
–––––––– 8,377 |
–––––––– 7,636 |
–––––––– 4,706 |
–––––––– – |
–––––––– – |
||
| –––––––– | –––––––– | –––––––– | –––––––– 2012 US\$000's |
–––––––– 2011 US\$000's |
–––––––– 2010 US\$000's |
||
| Charge to the income statement | |||||||
| Realised derivative financial instrument loss | 15,752 | – | – | ||||
| Unrealised derivative financial instruments loss | 13,308 –––––––– |
12,342 –––––––– |
– –––––––– |
||||
| 29,060 | 12,342 | – |
In November 2011, the Group entered into a number of deferred premium put options in respect of production from the OML 26 field. With the benefit of the options, the Group will receive a minimum amount on the options if the Brent crude oil market falls. These hedges are over a three year period from 1 January 2012 to 31 December 2014 and a total premium of US\$54.7 million will be expensed over this period. The maximum price protected is between US\$90 and US\$100/bbl (weighted average of US\$94.38/bbl over the period) with a US\$65/bbl floor which will ensure required repayments on the acquisition and development loan facility are met. These instruments have been classified as cash flow hedges, with a portion of the gains and losses on the instruments that are determined to be an effective hedge taken to equity and the ineffective portion, as well as any change in time value, recognised in the income statement for each period.
–––––––– –––––––– ––––––––
The fair value of the derivative liability at 31 December 2012 was US\$25.7 million (2011: US\$12.3 million) as reflected in the balance sheet. This represents the present value of the deferred premium to be paid. The maximum cost of the derivative liability is the value of the premium not yet paid.
The amounts reported in the balance sheet relating to derivative financial instruments mature as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Due within one year | 17,273 | 7,636 | – |
| Due within two to five years | 8,377 | 4,706 | – |
| –––––––– 25,650 |
–––––––– 12,342 |
–––––––– – |
|
| –––––––– | –––––––– | –––––––– |
Set out below is a comparison by category of carrying amounts and fair values of all the Group's financial instruments:
| Carrying amount ——————————————— |
Fair value ——————————————— |
|||||
|---|---|---|---|---|---|---|
| 2012 US\$000's |
2011 US\$000's |
2010 US\$000's |
2012 US\$000's |
2011 US\$000's |
2010 US\$000's |
|
| Financial assets | ||||||
| Cash and cash equivalents | 73,929 | 62,226 | 10,456 | 73,929 | 62,226 | 10,456 |
| Loans and receivables: | ||||||
| Trade and other debtors | 12,779 | 98 | – | 12,779 | 98 | – |
| Loan receivable | 6,900 | – | – | 6,900 | – | – |
| Receivable from licence | ||||||
| operating partners | 18,447 | 1,214 | – | 18,447 | 1,214 | – |
| –––––––– 112,055 –––––––– |
–––––––– 63,538 –––––––– |
–––––––– 10,456 –––––––– |
–––––––– 112,055 –––––––– |
–––––––– 63,538 –––––––– |
–––––––– 10,456 –––––––– |
| Carrying amount ——————————————— |
Fair value ——————————————— |
|||||
|---|---|---|---|---|---|---|
| 2012 US\$000's |
2011 US\$000's |
2010 US\$000's |
2012 US\$000's |
2011 US\$000's |
2010 US\$000's |
|
| Financial liabilities | ||||||
| Financial liabilities at fair value through profit and |
||||||
| loss – designated at initial recognition: |
||||||
| Derivative financial | ||||||
| instruments – Level 2 | 25,650 | 12,342 | – | 25,650 | 12,342 | – |
| Financial liabilities measured at amortised cost: |
||||||
| Trade creditors | 131 | 337 | – | 131 | 337 | – |
| Other creditors and | ||||||
| operating partners | 7,923 | 3,541 | 1,313 | 7,923 | 3,541 | 1,313 |
| Royalty payable | 3,421 | 2,319 | – | 3,421 | 2,319 | – |
| Loan facility | 95,821 | 101,329 | – | 93,275 | 96,339 | – |
| Convertible loan notes | 52,014 | 45,499 | – | 52,171 | 45,764 | – |
| –––––––– 184,960 |
–––––––– 165,367 |
–––––––– 1,313 |
–––––––– 182,571 |
–––––––– 160,642 |
–––––––– 1,313 |
|
| –––––––– | –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
Level 2 fair value measurements have been determined by reference to observable data in quoted markets at the balance sheet dates.
The fair value of bank borrowings and loan notes have been determined for each reporting date by discounting future cash outflows relating to the borrowings and loan notes respectively. Discount rate of 14% has been used to determine the fair value.
The Group's exposure to the risk of changes in market interest rates relates primarily to the Group's borrowings. The following table demonstrates the sensitivity to changes in LIBOR rate based on the average balance outstanding, with all other variables held constant, of the Group's profit before tax.
| Increase | Increase in Group loss US\$000's |
Decrease | Decrease in Group loss US\$000's |
|
|---|---|---|---|---|
| 2010 | ||||
| Interest payable | 1% –––––––– |
– –––––––– |
1% –––––––– |
– –––––––– |
| 2011 | ||||
| Interest payable | 1% –––––––– |
138 –––––––– |
1% –––––––– |
(138) –––––––– |
| 2012 | ||||
| Interest payable | 1% –––––––– |
1,078 –––––––– |
1% –––––––– |
(1,078) –––––––– |
The Group has limited exposure to Foreign exchange risk as all significant transactions are denominated in US dollars, being the Group's presentational currency. The impact of a 10% change in the Nigerian Naira to US dollar exchange rate would not be material in 2010, 2011 or in 2012.
The Group manages its capital to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. The Group's funding needs are met through a combination of debt and equity.
The capital structure of the Group consists of net debt, which includes the borrowings disclosed above after deducting cash and cash equivalents, and equity attributable to equity holders of the Company, comprising issued capital, reserves and retained earnings as disclosed in the statement of changes in equity.
The Group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross debt, as shown in the balance sheet, less cash and cash equivalents.
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. The Group reviews the credit risk of the entities that it sells its products to or that it enters into contractual arrangements with and will obtain guarantees and commercial letters of credit as may be considered necessary where risks are significant to the Group.
The carrying amount of the Groups financial assets represents the maximum credit exposure. The maximum credit exposure at the end of each reporting period was as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Trade and other receivables | 40,093 | 13,448 | 29,145 |
| Loans receivable | 6,900 | – | – |
| Cash and cash equivalents | 73,929 | 62,226 | 10,456 |
| –––––––– 120,922 |
–––––––– 75,674 |
–––––––– 39,601 |
|
| –––––––– | –––––––– | –––––––– |
The Group's sales are undertaken with one major international oil company with a high credit rating. The Directors performed regular reviews of the customers liquidity and credit rating, and do not believe that there is any exposure to credit risk in relation to the sale of oil.
The credit risk on cash is limited because the majority is deposited with banks with B and above credit ratings assigned by international credit rating agencies.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| At 1 January | 2,502 | – | – |
| Addition during the period | – | 2,492 | – |
| Unwinding of discount | 135 | 10 | – |
| At 31 December | –––––––– 2,637 |
–––––––– 2,502 |
–––––––– – |
| –––––––– | –––––––– | –––––––– |
The provision for decommissioning is in respect of OML 26 and was recognised following the final payment, signing and transfer of 45% ownership in OML 26 to FHN 26 Limited, a 100% owned subsidiary of the Group.
The provision represents the present value of the amounts that are expected to be incurred up to 2035 to decommission field activity undertaken to date. The provision was determined using FHN's internal estimates that Management believe form a reasonable basis for the expected future costs of decommissioning.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Liability component at 1 January/or incorporation | 45,499 | – | – |
| Proceeds on issue (liability component) | – | 45,764 | – |
| Issue costs | – | (686) | – |
| Unwinding of discount | 6,401 | 421 | – |
| Amortisation of issue costs | 114 | – | – |
| ––––––– 52,014 |
––––––– 45,499 |
––––––– – |
|
| Reported in: | ––––––– | ––––––– | ––––––– |
| Borrowings – non-current liabilities | 52,014 | 45,499 | – |
| Total liability component | ––––––– 52,014 |
––––––– 45,499 |
––––––– – |
| ––––––– | ––––––– | ––––––– |
Refer to Note 16 for additional information on the convertible loan notes.
| 2012 | 2011 | 2010 | ||
|---|---|---|---|---|
| US\$000's | US\$000's | US\$000's | ||
| Property, plant and equipment – other | (23) | (69) | – | |
| Property, plant and equipment – oil and gas assets | (119,555) | (116,207) | – | |
| Decommissioning provision | 2,242 | 2,127 | – | |
| Other temporary differences | 16,922 | 3,968 | – | |
| Tax losses | 6,738 | 8,433 | – | |
| Deferred tax asset/(liability) | ––––––– (93,676) |
––––––– (101,748) |
––––––– – |
|
| ––––––– | ––––––– | ––––––– | ||
| At | Credit/ | At | ||
| 1 January | (charge) | Acquisition | 31 December | |
| 2012 | for the year | of licence | 2012 | |
| US\$000's | US\$000's | US\$000's | US\$000's | |
| Analysis of movement during the year – 2012 | ||||
| Property, plant and equipment | (69) | 46 | – | (23) |
| Property, plant and equipment – | ||||
| oil and gas assets | (116,207) | (3,348) | – | (119,555) |
| Decommissioning provision | 2,127 | 115 | – | 2,242 |
| Other temporary differences | 3,968 | 12,954 | – | 16,922 |
| Tax losses | 8,433 –––––––– |
(1,695) –––––––– |
– –––––––– |
6,738 –––––––– |
| (101,748) | 8,072 | – | (93,676) | |
| –––––––– | –––––––– | –––––––– | –––––––– |
| At | Credit/ | At | ||
|---|---|---|---|---|
| 1 January | (charge) | Acquisition | 31 December | |
| 2011 | for the year | of licence | 2011 | |
| US\$000's | US\$000's | US\$000's | US\$000's | |
| Analysis of movement during the year – 2011 | ||||
| Property, plant and equipment | – | (69) | – | (69) |
| Property, plant and equipment – oil and gas assets | – | (1,022) | (115,185) | (116,207) |
| Decommissioning provision | – | 2,127 | – | 2,127 |
| Other temporary differences | – | 3,968 | – | 3,968 |
| Tax losses | – | 8,433 | – | 8,433 |
| –––––––– | –––––––– 13,437 |
–––––––– (115,185) |
–––––––– (101,748) |
|
| –––––––– | –––––––– | –––––––– | –––––––– |
At 31 December 2010 the Group had tax losses of US\$3.0 million in respect of which a deferred tax asset was not recognised as, at that date, there was insufficient evidence of future taxable profits against which these tax losses could be recovered. Such losses can be carried forward indefinitely. There were no other temporary differences as at 31 December 2010.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Authorised Share capital Ordinary shares of US\$0.065 |
320,000,000 | 135,000,000 | 120,000,000 |
| –––––––––– Number |
–––––––––– Equity share capital allotted \$000's |
–––––––––– Share premium \$000's |
|
| Allotted share capital and share premium 2010 |
|||
| Non-cash shares issued on incorporation(i) | 54,000,000 | 348 | 1,650 |
| Shares issued(ii) | 66,000,000 | 426 | 14,061 |
| Transfer of shares at a premium(iii) | – | – | 24,468 |
| As at 31 December 2010 | –––––––––– | –––––––––– | –––––––––– |
| 120,000,000 | 774 | 40,179 | |
| 2011 | –––––––––– | –––––––––– | –––––––––– |
| As at 1 January 2011 | 120,000,000 | 774 | 40,179 |
| Transfer of shares at a premium(iii) | – | – | 6,706 |
| Shares issued(ii) | 15,000,000 | 97 | 18,872 |
| As at 31 December 2011 | –––––––––– | –––––––––– | –––––––––– |
| 135,000,000 | 871 | 65,757 | |
| 2012 | –––––––––– | –––––––––– | –––––––––– |
| As at 1 January 2011 | 135,000,000 | 871 | 65,757 |
| Transfer of shares at a premium(iii) | – | – | 1,514 |
| Shares cancelled(iv) | (5,016,667) | (32) | – |
| As at 31 December 2012 | –––––––––– | –––––––––– | –––––––––– |
| 129,983,333 | 839 | 67,271 | |
| –––––––––– | –––––––––– | –––––––––– |
(i) Non-cash shares issued on incorporation relate to the issue of shares to settle professional fees in line with contractual terms for services rendered to the Group.
(ii) Unpaid share capital amounted to \$0.6 million and \$14.4 million at 31 December 2011 and 2010 respectively. No unpaid share capital remained at 31 December 2012.
(iii) Under the terms initial shareholder subscription agreements, where shares were subsequently resold by initial subscribers, the full premium on resale was remitted to the Company.
a. In 2010, 20,400,000 shares in the Company were resold at a premium, all of which was remitted to the Company.
b. In 2011, 6,750,000 of shares in the Company were resold at a premium, all of which was remitted to the Company.
c. In 2012, 2,400,000 of shares in the Company were resold at a premium, all of which was remitted to the Company.
(iv) In 2012, 5,016,667 of shares issued on incorporation where share capital remained unpaid by the initial subscribers were cancelled by the Company. No share premium related to the shares, as they were issued at par value.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Nigerian CITA | 23 | – | – |
| Nigerian PPT | 784 | – | – |
| ––––––– 807 |
––––––– – |
––––––– – |
|
| Deferred tax | ––––––– (8,072) |
––––––– (13,437) |
––––––– – |
| ––––––– (8,072) |
––––––– (13,437) |
––––––– – |
|
| Overall tax credit | ––––––– (7,265) |
––––––– (13,437) |
––––––– – |
| The overall tax credit can be reconciled as follows: | ––––––– | ––––––– | ––––––– |
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Pre-tax loss | (29,980) | (19,915) | (6,819) |
| Tax at the domestic tax rate of 30% | (8,995) | (5,975) | (2,046) |
| Tax effect of items which are not deductible for tax | 5,752 | 138 | 387 |
| Tax effect of deferred tax assets not previously recognised | – | (3,770) | – |
| Effect of different tax rates | (4,022) | (3,830) | (1,360) |
| Tax losses not recognised | – | – | 3,019 |
| Tax credit for the period | ––––––– (7,265) |
––––––– (13,437) |
––––––– – |
| ––––––– | ––––––– | ––––––– |
As highlighted in Note 3 the application of tax legislation in jurisdictions in which the Group operates can be uncertain and subject to interpretation. The Group calculates the tax charge for each period using the latest information available, taking external advice where necessary, in order to arrive at the best estimate of the final tax position. Revisions to tax liabilities (either upward or downward) may occur as the Group's tax filings and royalties are agreed with the relevant authorities in future periods.
The Group has no non-cancellable commitments in respect to operating leases. Office lease costs incurred amounted to \$0.3 million and \$0.2 million for the years ended 31 December 2012 and 2011 respectively. No lease costs were incurred in the period ended 31 December 2010.
The Group provided a letter of credit in favour of Nigeria Petroleum Development Company for US\$20 million with a lien of US\$10 million. The letter of credit has been provided in respect of the Group's obligations under the Joint Operating Agreement for OML 26.
On 2 April 2012, the Group signed an Asset Sale and Purchase Agreement (ASPA) jointly with EER (Colobus) Nigeria Limited for the acquisition of a combined 18% interest in OML 113, with each party holding 9% interest. Total consideration payable by the Group under the ASPA is US\$40.0 million. In the year ended 31 December 2012, the Group had paid a US\$6.0 million deposit, with the remaining US\$34.0 million payable on completion of the acquisition, which is anticipated to be in 2013.
The Group operates a Long Term Incentive Plan (LTIP) for employees and directors. The Group's policy is to award options or deferred shares to employees and directors.
| Grant date | Method of settlement accounting |
Number of | instruments Vesting conditions | Contractual life of options |
|---|---|---|---|---|
| 22 June 2012 | Equity | 643,000 | Production levels exceed 8,000 bopd net or the market value of an ordinary share in the Company reaches or exceeds \$2.32 |
10 years |
Details of the share options outstanding during the period are as follows:
| 2012 —————–———— |
2011 —————–———— |
2010 —————–———— |
||||
|---|---|---|---|---|---|---|
| Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
|
| Outstanding at beginning | ||||||
| of period | – | – | – | – | – | – |
| Granted during period | 643,000 | 1.5 | – | – | – | – |
| Exercised during period | – | – | – | – | – | – |
| Lapsed during period | – –––––––– |
– –––––––– |
– –––––––– |
– –––––––– |
– –––––––– |
– –––––––– |
| Outstanding at end of period | 643,000 | 1.5 | – | – | – | – |
| Exercisable at end of period | –––––––– – |
–––––––– – |
–––––––– – |
–––––––– – |
–––––––– – |
–––––––– – |
| –––––––– | –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
The weighted average remaining contractual life of the options outstanding at 31 December 2012 was 9.5 years.
The options granted during the period have been valued by reference to the Barrier option valuation model. The inputs used in the measurement of the fair value at grant date of the equity-settled share-based payment were as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Weighted average share price (cents) | 200.0 | – | – |
| Exercise price (cents) | 150.0 | – | – |
| Weighted average target price before eligibility | |||
| to exercise (barrier) (pence) | 232.0 | – | – |
| Expected volatility | 25% | – | – |
| Expected life (years) | 1.5 | – | – |
| Risk free rate | 0.25% | – | – |
| Expected dividends | nil | – | – |
| ––––––– | ––––––– | ––––––– |
The Group's shares are not traded on a recognised market. Therefore in assessing volatility, an external assessment was undertaken by New Bridge Street. The volatility was determined through share price movements of Nigerian listed entities operating in the oil & gas and basic resources sector.
The Group recognised total expenses related to the above equity settled share-based payment transactions in the form of options in 2012 of US\$0.3 million.
| Grant date | Method of settlement accounting |
Number of | instruments Vesting conditions | Contractual life of options |
|---|---|---|---|---|
| 30 December 2011 | Equity | 14,000,000 | Production levels exceed 8,000 bopd net or the market value of an ordinary share in the Company reaches or exceeds \$2.32 |
2.0 years |
| 1 June 2012 | Equity | 500,000 | Production levels exceed 8,000 bopd net or the market value of an ordinary share in the Company reaches or exceeds \$2.32 |
2.5 years |
Details of the share awards outstanding during the period are as follows:
| 2012 —————–———— |
2011 —————–———— |
2010 —————–———— |
||||
|---|---|---|---|---|---|---|
| Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
|
| Outstanding at beginning | ||||||
| of period | 14,000,000 | nil | – | – | – | – |
| Granted during period | 500,000 | – | 14,000,000 | nil | – | – |
| Exercised during period | – | – | – | – | – | – |
| Lapsed during period | – | – | – ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– |
– | – | – |
| Outstanding at end of period 14,500,000 | nil 14,000,000 ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– |
nil | – | – | ||
| Exercisable at end of period | – | – | – ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– |
– | – | – |
The weighted average remaining contractual life of the share awards outstanding at 31 December 2012 was 1 year.
The share awards granted during the period have been valued by reference to the Barrier option valuation model. The inputs used in the measurement of the fair value at grant date of the equity-settled share-based payment were as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Weighted average share price (cents) | 200.0 | 200.0 | – |
| Exercise price (cents) | nil | nil | – |
| Weighted average target price before eligibility | |||
| to exercise (barrier) (pence) | 232.0 | 232.0 | – |
| Expected volatility | 25% | 25% | – |
| Expected life (years) | 1.5 | 2 | – |
| Risk free rate | 0.25% | 0.25% | – |
| Expected dividends | nil | nil | – |
| ––––––– | ––––––– | ––––––– |
The Group's shares are not traded on a recognised market. Therefore in assessing volatility, an external assessment was undertaken by New Bridge Street. The volatility was determined through share price movements of Nigerian listed entities operating in the oil & gas and basic resources sector.
The Group recognised total expenses related to the above equity-settled share-based payment transactions in the form of deferred share awards during the year ended 31 December 2012 of US\$12.0 million. While the share awards were issued on 30 December 2011, no charge was recognised in the year ended 31 December 2011 on the basis of materiality.
| Grant date | Method of settlement accounting |
Number of | instruments Vesting conditions | Contractual life of options |
|---|---|---|---|---|
| 1 March 2011 1 July 2011 |
Equity Equity |
200,000 150,000 |
The market value of an ordinary share in the Company reaches or exceeds \$2.70 or the company completes a listing on a recognised stock exchange by 1 September 2013 |
2.5 years |
Details of the share awards outstanding during the period are as follows:
| 2012 —————–———— |
2011 —————–———— |
2010 —————–———— |
||||
|---|---|---|---|---|---|---|
| Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
|
| Outstanding at beginning | ||||||
| of period | 350,000 | nil | – | – | – | – |
| Granted during period | – | – | 350,000 | nil | – | – |
| Exercised during period | – | – | – | – | – | – |
| Lapsed during period | – ––––––––– ––––––––– |
– | – | – | – –––––––––––––––––– ––––––––– ––––––––– |
– |
| Outstanding at end of period | 350,000 ––––––––– ––––––––– |
nil | 350,000 | nil | – –––––––––––––––––– ––––––––– ––––––––– |
– |
| Exercisable at end of period | – | – | – | – | – | – |
––––––––– ––––––––– –––––––––––––––––– ––––––––– ––––––––– The weighted average remaining contractual life of the options outstanding at 31 December 2012 was 1 year.
The options granted during the period have been valued by reference to the Barrier option valuation model. The inputs used in the measurement of the fair value at grant date of the equity-settled share-based payment were as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Weighted average share price (cents) | 200.0 | 200.0 | – |
| Exercise price (cents) | nil | nil | – |
| Weighted average target price before eligibility | |||
| to exercise (barrier) (pence) | 270.0 | 270.0 | – |
| Expected volatility | 25% | 25% | – |
| Expected life (years) | 2.5 | 2.5 | – |
| Risk free rate | 0.25% | 0.25% | – |
| Expected dividends | nil | nil | – |
| ––––––– | ––––––– | ––––––– |
The Group's shares are not traded on a recognised market. Therefore in assessing volatility, an external assessment was undertaken by New Bridge Street. The volatility was determined through share price movements of Nigerian listed entities operating in the oil & gas and basic resources sector.
The Group recognised total expenses related to the above equity-settled share-based payment transactions in the form of deferred share awards of \$0.10 million and \$0.16 million during the years ended 31 December 2011 and 2012 respectively.
On 21 April 2011 the Group granted Afren plc an irrevocable call option to purchase 30 million shares in First Hydrocarbon Nigeria Limited at US\$1 per share. The call option however limited Afren to exercise the option and purchase shares only to the extent that Afren's shareholding in Group does not exceed 45%. The option was granted as consideration for the services received from Afren in securing additional investment in the Group by CBO Oil and GAS FHN Investments Services Vehicle Limited. The options were granted on 30 June 2011 and expire after 10 years if they remain unexercised.
Details of the share options outstanding during the period are as follows:
| 2012 —————–———— |
2011 —————–———— |
2010 —————–———— |
||||
|---|---|---|---|---|---|---|
| Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
Number of share options |
Weighted average exercise price \$ |
|
| Outstanding at beginning | ||||||
| of Period | 23,250,000 | 1 | – | – | – | – |
| Granted during period | – | – | 30,000,000 | 1 | – | – |
| Exercised during period | – | – | (6,750,000) | 1 | – | – |
| Lapsed during period | – | – | – | – | – | – |
| Outstanding at end of period 23,250,000 | 1 | ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– 23,250,000 |
1 | – | – | |
| Exercisable at end of period 23,250,000 | 1 | ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– 23,250,000 |
1 | – | – | |
| ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– ––––––––– |
The weighted average remaining contractual life of the options outstanding at 31 December 2012 was 8.5 years.
The options granted during the period have been valued by reference to the Barrier option valuation model. The inputs used in the measurement of the fair value at grant date of the equity-settled call option were as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| Weighted average share price (cents) | – | 200.0 | – |
| Exercise price (cents) | – | 100.0 | – |
| Expected number of shares that will be exercised | – | 9,167,000 | – |
| Expected volatility | – | 25% | – |
| Expected life (years) | – | 7.7 | – |
| Risk free rate | – | 2.0% | – |
| Expected dividends | – | nil | – |
| ––––––– | ––––––– | ––––––– |
The Group's shares are not traded on a publically available market. Therefore in assessing volatility, an external assessment was undertaken by New Bridge Street. The volatility was determined through share price movements of Nigerian listed entities operating in the oil & gas and basic resources sector.
The Group recognised \$10.9 million cost of equity related to the above equity-settled call option during the year ended 31 December 2011. The fair value has been charged directly to share premium on the basis that it is a cost associated with the issue of shares to CBO Oil and GAS FHN Investments Services Vehicle Limited.
On 21 October 2010, the Group signed a Definitive Agreement with Shell Petroleum Development Company of Nigeria Ltd, Total E&P Nigeria Ltd and Nigeria Agip Oil Company for the acquisition of their combined 45% interest in OML 26. Total consideration under the Definitive Agreement was US\$147.5 million including a 10% deposit paid on signing of the agreement. Following government approval and finalisation of the joint operating agreement, the transaction was completed on 1 December 2011 with the remaining US\$132.75 million consideration being settled in cash.
The fair values of identifiable assets and liabilities acquired by Group were as follows:
| Fair value to the Group US\$000's |
|
|---|---|
| Oil and gas assets | 149,992 |
| Decommissioning liability | (2,492) |
| Deferred tax liability | (115,185) |
| Fair value of share of net identified assets and liabilities | –––––––– 32,315 |
| Total consideration | 147,500 |
| Goodwill recognised on acquisition | 115,185 |
| –––––––– |
Acquisition related costs amounting to US\$4.5 million were recognised as an expense and were included in administrative expenses in the consolidated income statement for the year ended 31 December 2011.
On 2 April 2012, the Group signed an Asset Sale and Purchase Agreement (ASPA) jointly with EER (Colobus) Nigeria Limited for the acquisition of a combined 18% interest in OML 113, with each party holding 9% interest. OML 113 is an oil mining license located in the Benin Basin, approximately 24km offshore of western Nigeria. Total consideration payable by the Group under the ASPA is US\$40.0 million. In the year ended 31 December 2012, the Group had paid a US\$6.0 million deposit , with the remaining US\$34.0 million payable on completion of the acquisition, which is anticipated to be in 2013. As at 31 December 2012, the acquisition had not been completed and control had not yet passed. The deposit has been recognised as a prepayment as at 31 December 2012.
| Share-based | |||
|---|---|---|---|
| payment | |||
| Loan notes | reserve | Total | |
| US\$000's | US\$000's | US\$000's | |
| Group | |||
| At incorporation on 25 June 2009 | – –––––––– |
– –––––––– |
– –––––––– |
| At 31 December 2010 | – | – | – |
| Convertible loan notes, equity component | –––––––– 4,172 |
–––––––– – |
–––––––– 4,172 |
| Share-based payments, call options | – | 10,905 | 10,905 |
| Share-based payments, services | – –––––––– |
101 –––––––– |
101 –––––––– |
| At 31 December 2011 | 4,172 | 11,006 | 15,178 |
| Share-based payments, services | –––––––– – |
–––––––– 12,042 |
–––––––– 12,042 |
| At 31 December 2012 | –––––––– 4,172 |
–––––––– 23,048 |
–––––––– 27,220 |
| –––––––– | –––––––– | –––––––– |
Loan notes reserve represented the equity component of the proceeds following the issue of the convertible note as detailed in Note 18.
Share-based payment reserve represents the fair value of the equity settled awards granted by the Group as detailed in Note 23.
In February 2013 the Company received a share purchase offer at a price that exceeded the share price vesting condition associated with both the share option scheme and the deferred share awards. As a result, a total of 643,000 share options vested along with 14,850,000 deferred shares. The deferred shares were subsequently issued.
In March 2013 the Group extended the repayment terms in respect of the loan receivable from EER (Colobus) Nigeria Limited. The extended terms now require repayment of the loan in full in October 2013.
Other than the matters noted above, no other post balance sheet events have been identified that would require disclosure.
Afren Nigeria Holdings Limited, a significant shareholder in the Company, provides operational and administrative services to the Group. All amounts are supported by contracts and are undertaken at armslength. Amounts owed by and to Afren Nigeria Holdings Limited were as follows:
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Payables outstanding | 9,591 | 5,411 | 5,448 |
| Transactions between the Company and its shareholders were as follows | –––––––– | –––––––– | –––––––– |
| US\$000's | |||
| 2012 | |||
| Administrative expense | 3,341 –––––––– |
||
| 2011 | |||
| Administrative expense | 5,250 | ||
| Net loan advances/(repayments) | (2,250) –––––––– |
||
| 2010 | |||
| Administrative expense | 1,313 | ||
| Net loan advances | 4,135 |
As disclosed in Note 23, the Group has granted Afren plc an irrevocable call option to purchase 30 million shares in First Hydrocarbon Nigeria Limited at US\$1 per share. Afren plc is the ultimate parent entity of Afren Nigeria Holdings Limited, a shareholder in the Group.
––––––––
The remuneration of the Directors, who are key management personnel of the Group, is set out below in aggregate for each of the categories specified in IAS 24 'Related Party Disclosures'.
| 2012 | 2011 | 2010 | |
|---|---|---|---|
| US\$000's | US\$000's | US\$000's | |
| Short-term employee benefits | 978 | 858 | 297 |
| Share-based payment | 11,763 | 101 | – |
| –––––––– 12,741 |
–––––––– 959 |
–––––––– 297 |
|
| –––––––– | –––––––– | –––––––– |
The unaudited pro forma statement of net assets of the Enlarged Group set out below has been prepared on the basis discussed below, and in accordance with the requirements of item 20.2 of Annex I and items 1 to 6 of Annex II of the Prospectus Directive, to illustrate the effect of the acquisition of FHN on the Group's net assets as if it had occurred as at 31 December 2012. It has been prepared for illustrative purposes only and, because of its nature, addresses a hypothetical situation and therefore does not represent the Group's actual financial position or results as at such date. Future results of operations may differ materially from those presented below due to various factors.
The pro forma statement is based on the net assets of the Group as at 31 December 2012, which have been extracted without material adjustment from Afren's published audited annual accounts as at 31 December 2012. The net assets of FHN as at 31 December 2012 have been extracted without material adjustment from the audited balance sheet of FHN as restated under the Group's accounting policies as at 31 December 2012, as set out in Part 5 of this document. The other adjustments are discussed in the notes below. The accounting policies used in the preparation of the unaudited pro forma statement are consistent with those used by Afren in its audited consolidated financial statements as at and for the year ended 31 December 2012.
| Adjustments | ||||||
|---|---|---|---|---|---|---|
| —————————————————–———————————— FHN |
Purchase consideration and |
Pro forma consolidated net |
||||
| Afren plc | Group | Acquisition | transaction Consolidation | assets | ||
| 31 December 31 December | accounting | costs | adjustments 31 December | |||
| US\$ millions | 2012 | 2012 | (Note 1) | (Note 2) | (Note 3) | 2012 |
| Assets | ||||||
| Non-current assets | ||||||
| Intangible oil and gas assets | 875.9 | – | 875.9 | |||
| Property, plant and equipment | 1,703.8 | 150.1 | 1,853.9 | |||
| Goodwill | - | 115.2 | 20.2 | 135.4 | ||
| Prepayments | 88.4 | – | 88.4 | |||
| Investment | 16.6 | – | (15.7) | 0.9 | ||
| Derivative financial instruments | 10.4 | – | 10.4 | |||
| –––––––– 2,695.1 |
–––––––– 265.3 |
–––––––– 4.5 |
–––––––– | –––––––– | –––––––– 2,964.9 |
|
| Current assets | ||||||
| Inventories | 94.4 | – | – | 94.4 | ||
| Trade and other receivables | 270.1 | 47.0 | (9.6) | 307.5 | ||
| Cash and cash equivalents | 524.8 | 73.9 | (39.0) | 559.7 | ||
| –––––––– 889.3 |
–––––––– 120.9 |
–––––––– – |
–––––––– (39.0) |
–––––––– (9.6) |
–––––––– 961.6 |
|
| Liabilities | ||||||
| Current liabilities | ||||||
| Derivative financial instruments | (14.0) | (17.3) | (31.3) | |||
| Borrowings | (189.4) | (28.1) | (217.5) | |||
| Obligations under finance lease | (19.3) | – | (19.3) | |||
| Trade and other payables | (585.0) | (55.2) | 9.6 | (630.6) | ||
| –––––––– (807.7) |
–––––––– (100.6) |
–––––––– – |
–––––––– – |
–––––––– 9.6 |
–––––––– (898.7) |
|
| Non-current liabilities | ||||||
| Other payables | – | (1.9) | (1.9) | |||
| Deferred tax liabilities | (383.9) | (93.7) | (477.6) | |||
| Provision for decommissioning | (36.7) | (2.6) | (39.3) | |||
| Borrowings | (823.9) | (119.7) | (943.6) | |||
| Obligations under finance lease | (98.1) | – | (98.1) | |||
| Derivative financial instruments | (6.7) –––––––– |
(8.4) –––––––– |
–––––––– | –––––––– | –––––––– | (15.1) –––––––– |
| (1,349.3) | (226.3) | (1,575.6) | ||||
| Net assets | –––––––– 1,427.4 |
–––––––– 59.3 |
–––––––– 4.5 |
–––––––– (39.0) |
–––––––– – |
–––––––– 1,452.2 |
| –––––––– | –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
| US\$ million | |
|---|---|
| Cash consideration | 37.0 |
| Carrying value of Afren's existing 46.7% interest | 15.7 –––––––– |
| Total purchase consideration | 52.7 |
| Net assets of FHN as at 31 December 2012 | 59.3 |
| Afren's 54.8% share of net assets | (32.5) –––––––– |
| Purchase consideration in excess of net assets | 20.2 |
The US\$20.2 million purchase consideration in excess of net assets has been allocated to goodwill. The amount allocated is provisional and subject to a fair value exercise on completion of the Acquisition.
The adjustment to cash and cash equivalents of US\$39.0 million represents the US\$37.0 million cash consideration to be paid for the additional interest in FHN along with acquisition related costs of US\$2.0 million.
Elimination of amounts receivable by Afren from FHN as at 31 December 2012.
Save for the adjustments set out above, no adjustment has been made to reflect any trading or other transactions undertaken since the date of the unadjusted information.
The Board of Directors on behalf of Afren plc Kinnaird House 1 Pall Mall East London SW1Y 5AU
Merrill Lynch International 2 King Edward Street London EC1A 1HQ
2 May 2013
Dear Sirs,
We report on the pro forma financial information (the "Pro forma financial information") set out in Part 6 of the Class 1 Circular relating to the acquisition of Target dated 2 May 2013 of Afren plc (the "Company" and, together with its subsidiaries, the "Group") (the "Circular"), which has been prepared as described in the basis of preparation, for illustrative purposes only, to provide information about how the transaction might have affected the financial information presented on the basis of the accounting policies adopted by the Company in preparing the financial statements for the period ended 31 December 2012. This report is required by Annex I item 20.2 of Commission Regulation (EC) No 809/2004 (the "Prospectus Directive Regulation") as applied by Listing Rule 13.3.3R and is given for the purpose of complying with that requirement and for no other purpose.
It is the responsibility of the directors of the Company (the "Directors") to prepare the Pro forma financial information in accordance with Annex I item 20.2 and Annex II items 1 to 6 of the Prospectus Directive Regulation as applied by Listing Rule 13.3.3R.
It is our responsibility to form an opinion, in accordance with Annex I item 20.2 of the Prospectus Directive Regulation, as to the proper compilation of the Pro forma financial information and to report that opinion to you in accordance with Annex II item 7 of the Prospectus Directive Regulation as applied by Listing Rule 13.3.3R.
Save for any responsibility which we may have to those persons to whom this report is expressly addressed and which we may have to ordinary shareholders as a result of the inclusion of this report in the Circular, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with Listing Rule 13.4.1R(6), consenting to its inclusion in the Circular.
In providing this opinion we are not updating or refreshing any reports or opinions previously made by us on any financial information used in the compilation of the Pro forma financial information, nor do we accept responsibility for such reports or opinions beyond that owed to those to whom those reports or opinions were addressed by us at the dates of their issue.
We conducted our work in accordance with the Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. The work that we performed for the purpose of making this report, which involved no independent examination of any of the underlying financial information, consisted primarily of comparing the unadjusted financial information with the source documents, considering the evidence supporting the adjustments and discussing the Pro forma financial information with the Directors.
We planned and performed our work so as to obtain the information and explanations we considered necessary in order to provide us with reasonable assurance that the Pro forma financial information has been properly compiled on the basis stated and that such basis is consistent with the accounting policies of the Company.
Our work has not been carried out in accordance with auditing or other standards and practices generally accepted in jurisdictions outside the United Kingdom, including the United States of America, and accordingly should not be relied upon as if it had been carried out in accordance with those standards or practices.
In our opinion:
Yours faithfully
Chartered Accountants
Deloitte LLP is a limited liability partnership registered in England and Wales with registered number OC303675 and its registered office at 2 New Street Square, London EC4A 3BZ, United Kingdom. Deloitte LLP is the United Kingdom member firm of Deloitte Touche Tohmatsu Limited ("DTTL"), a UK private company limited by guarantee, whose member firms are legally separate and independent entities. Please see www.deloitte.co.uk/about for a detailed description of the legal structure of DTTL and its member firms.
March 25, 2013
Mr. Femi Bajomo First Hydrocarbon Nigeria Limited 8th Floor, Octagon Towers 13A A.J. Marinho Drive Victoria Island Annexe Lagos Nigeria
Dear Mr. Bajomo:
In accordance with your request, we have estimated the proved (1P), proved plus probable (2P), and proved plus probable plus possible (3P) reserves and future revenue, as of December 31, 2012, for certain oil properties located in Ogini and Isoko Fields, Oil Mining Lease (OML) 26, onshore Nigeria, in which First Hydrocarbon Nigeria Limited (FHN) owns a 45 percent working interest. Also as requested, we have estimated the gross (100 percent) contingent oil resources, as of December 31, 2012, for Aboh, Isoko, Ogini, Ovo, and Ozoro Fields located in OML 26. We completed our evaluation on or about the date of this letter. For the reserves, this report has been prepared using constant price and cost parameters specified by FHN, as discussed in subsequent paragraphs of this letter. Monetary values shown in this report are expressed in United States dollars (\$) or thousands of United States dollars (M\$).
The estimates in this report have been prepared in accordance with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System (PRMS) approved by the Society of Petroleum Engineers (SPE) except that, as requested, abandonment costs have not been included in our estimates of future net revenue. As presented in the 2007 PRMS, petroleum accumulations can be classified, in decreasing order of likelihood of commerciality, as reserves, contingent resources, or prospective resources. Different classifications of petroleum accumulations have varying degrees of technical and commercial risk that are difficult to quantify; thus reserves, contingent resources, and prospective resources should not be aggregated without extensive consideration of these factors. Definitions are presented immediately following this letter.
Reserves are those quantities of petroleum anticipated to be commercially recoverable from known accumulations by application of development projects from a given date forward under defined conditions. Reserves must be discovered, recoverable, commercial, and remaining as of the evaluation date based on the planned development projects to be applied. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be commercially recoverable; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.
As presented in the accompanying summary projections, Tables I through III, we estimate the oil reserves and future net revenue to the FHN interest in these properties, as of December 31, 2012, to be:
Mr. Femi Bajomo First Hydrocarbon Nigeria Limited March 25, 2013 Page 2 of 4
| Oil Reserves (MBBL) | |||||
|---|---|---|---|---|---|
| Gross | Effective Working | Future Net Revenue (M\$) | |||
| (100 Percent) | Interest Before | Net Entitlement | Present Worth | ||
| Category | Before Royalties | Royalties | (1)After Royalties(1) | Total | at 10% |
| Proved (1P) | 057,694.5 | 25,962.5 | 20,770.0 | 244,802.0 | 129,956.1 |
| Proved + Probable (2P) | 134,581.0 | 60,561.5 | 48,449.2 | 585,865.3 | 268,756.3 |
| Proved + Probable + Possible (3P) | 198,594.1 | 89,367.4 | 71,493.9 | 890,675.3 | 399,746.3 |
(1) Net entitlement reserves are after deductions for Nigerian Government 20 percent royalty burdens.
The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. No gas market exists for these properties; therefore, gas reserves have not been estimated for this report.
The estimates of reserves shown in this report are for 1P, 2P, and 3P reserves. The 1P reserves are inclusive of proved developed producing, proved developed non-producing, and proved undeveloped reserves. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.
Gross revenue for the reserves shown in this report is after deductions for royalties. Future net revenue is after deductions for FHN's share of Education, Niger Delta Development Commission, and Petroleum Profit taxes; capital costs; and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
As requested, this report has been prepared using an oil price specified by FHN of \$100.00 per barrel. The oil price is held constant throughout the lives of the properties.
Operating costs used in this report are based on operating expense records of Nigerian Petroleum Development Company Ltd (NPDC), the operator of the properties, as provided by Atlantic Energy SA (Atlantic), and on analogy to other Nigerian properties similar to OML 26. Atlantic has an alliance agreement with NPDC. These costs include the overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the field levels. As requested, operating costs are limited to direct lease- and field-level costs and a portion of the headquarters general and administrative overhead expenses necessary to operate the properties. Also as requested, operating costs are held constant throughout the lives of the properties.
Capital costs used in this report were provided by Atlantic and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, license extension fees, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. As requested, capital costs are held constant to the date of expenditure. Also as requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.
Contingent resources are those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from known accumulations, but for which the applied project or projects are not yet considered
Mr. Femi Bajomo First Hydrocarbon Nigeria Limited March 25, 2013 Page 3 of 4
mature enough for commercial development because of one or more contingencies. The contingent resources shown in this report are contingent upon approval of a development plan and, subsequently, commitment from the operator to complete the development project. If these contingencies are successfully addressed, some portion of the contingent resources estimated in this report may be reclassified as reserves; our estimates have not been risked to account for the possibility that the contingencies are not successfully addressed. This report does not include economic analysis for these discoveries. Based on analogous field developments, it appears that the best estimate contingent resources in this report have a reasonable chance of being commercial.
We estimate the gross (100 percent) contingent oil resources for these properties, as of December 31, 2012, to be:
| Gross (100 Percent) Contingent Oil Resources |
|
|---|---|
| Category | (MMBBL) |
| Low Estimate (1C) | 42.0 |
| Best Estimate (2C) | 68.0 |
| High Estimate (3C) | 99.7 |
The oil volumes shown include crude oil only. Oil volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons. No gas market exists for these properties; therefore, contingent gas resources have not been estimated for this report.
The contingent resources shown in this report have been estimated using deterministic methods. Once all contingencies have been successfully addressed, the approximate probability that the quantities of contingent resources actually recovered will equal or exceed the estimated amounts is generally inferred to be 90 percent for the low estimate, 50 percent for the best estimate, and 10 percent for the high estimate. The estimates of contingent resources included herein have not been adjusted for development risk.
This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
The reserves and contingent resources shown in this report are estimates only and should not be construed as exact quantities. Estimates may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. Our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the volumes, and that our projections of future production will prove consistent with actual performance. If these volumes are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received, and costs incurred may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property
Mr. Femi Bajomo First Hydrocarbon Nigeria Limited March 25, 2013 Page 4 of 4
ownership interests. The reserves and contingent resources in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with generally accepted petroleum engineering and evaluation principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to classify, categorize, and estimate volumes in accordance with the 2007 PRMS definitions and guidelines. A portion of the reserves shown in this report are for behind-pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based, and the contingent resources shown in this report are for undeveloped locations. Such volumes are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from FHN, Atlantic, NPDC, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The contractual rights to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer
/s/ Dan Paul Smith /s/ John G. Hattner
By: By:
Dan Paul Smith, P.E. 49093 John G. Hattner, P.G. 559 Senior Vice President Senior Vice President
By:
Date Signed: March 25, 2013 Date Signed: March 25, 2013
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
This document contains information excerpted from definitions and guidelines prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE).
Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth's crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.
These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that this document will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.
It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements.
The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project's economic feasibility, its productive life, and its related cash flows.
Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare cases, non-hydrocarbon content could be greater than 50%.
The term "resources" as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth's crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered "conventional" or "unconventional."
Figure 1-1 is a graphical representation of the SPE/WPC/ AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.
The "Range of Uncertainty" reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the "Chance of
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Commerciality", that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources").
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage (see Production Measurement, section 3.2).
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.
PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of those in-place quantities that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.
This concept of a project-based classification system is further clarified by examining the primary data sources contributing to an evaluation of net recoverable resources (see Figure 1-2) that may be described as follows:
Figure 1-2: Resources Evaluation Data Sources.
In context of this data relationship, "project" is the primary element considered in this resources classification, and net recoverable resources are the incremental quantities derived from each project. Project represents the link between the petroleum accumulation and the decision-making process. A project may, for example, constitute the development of a single reservoir or field, or an incremental development for a producing field, or the integrated development of several fields and associated facilities with a common ownership. In general, an individual project will represent the level at which a decision is made whether or not to proceed (i.e., spend more money) and there should be an associated range of estimated recoverable quantities for that project.
An accumulation or potential accumulation of petroleum may be subject to several separate and distinct projects that are at different stages of exploration or development. Thus, an accumulation may have recoverable quantities in several resource classes simultaneously.
In order to assign recoverable resources of any class, a development plan needs to be defined consisting of one or more projects. Even for Prospective Resources, the estimates of recoverable quantities must be stated in terms of the sales products derived from a development program assuming successful discovery and commercial development. Given the major uncertainties involved at this early stage, the development program will not be of the detail expected in later stages of maturity. In most cases, recovery efficiency may be largely based on analogous projects. In-place quantities for which a feasible project cannot be defined using current, or reasonably forecast improvements in, technology are classified as Unrecoverable.
Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on a forecast of the conditions that will exist during the time period encompassed by the project's activities (see
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
Commercial Evaluations, section 3.1). "Conditions" include technological, economic, legal, environmental, social, and governmental factors. While economic factors can be summarized as forecast costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms, and taxes.
The resource quantities being estimated are those volumes producible from a project as measured according to delivery specifications at the point of sale or custody transfer (see Reference Point, section 3.2.1). The cumulative production from the evaluation date forward to cessation of production is the remaining recoverable quantity. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project (see Evaluation and Reporting Guidelines, section 3.0).
The supporting data, analytical processes, and assumptions used in an evaluation should be documented in sufficient detail to allow an independent evaluator or auditor to clearly understand the basis for estimation and categorization of recoverable quantities and their classification.
The basic classification requires establishment of criteria for a petroleum discovery and thereafter the distinction between commercial and sub-commercial projects in known accumulations (and hence between Reserves and Contingent Resources).
A discovery is one petroleum accumulation, or several petroleum accumulations collectively, for which one or several exploratory wells have established through testing, sampling, and/or logging the existence of a significant quantity of potentially moveable hydrocarbons.
In this context, "significant" implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place volume demonstrated by the well(s) and for evaluating the potential for economic recovery. Estimated recoverable quantities within such a discovered (known) accumulation(s) shall initially be classified as Contingent Resources pending definition of projects with sufficient chance of commercial development to reclassify all, or a portion, as Reserves. Where in-place hydrocarbons are identified but are not considered currently recoverable, such quantities may be classified as Discovered Unrecoverable, if considered appropriate for resource management purposes; a portion of these quantities may become recoverable resources in the future as commercial circumstances change or technological developments occur.
Discovered recoverable volumes (Contingent Resources) may be considered commercially producible, and thus Reserves, if the entity claiming commerciality has demonstrated firm intention to proceed with development and such intention is based upon all of the following criteria:
To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.
The horizontal axis in the Resources Classification (Figure 1.1) defines the range of uncertainty in estimates of the quantities of recoverable, or potentially recoverable, petroleum associated with a project. These estimates include both technical and commercial uncertainty components as follows:
Where commercial uncertainties are such that there is significant risk that the complete project (as initially defined) will not proceed, it is advised to create a separate project classified as Contingent Resources with an appropriate chance of commerciality.
The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution (see Deterministic and Probabilistic Methods, section 4.2).
When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:
When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately (see Category Definitions and Guidelines, section 2.2.2).
These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production, it is useful to consider the range of potentially recoverable quantities independently of such a risk or consideration of the resource class to which the quantities will be assigned.
Evaluators may assess recoverable quantities and categorize results by uncertainty using the deterministic incremental (riskbased) approach, the deterministic scenario (cumulative) approach, or probabilistic methods (see "2001 Supplemental Guidelines," Chapter 2.5). In many cases, a combination of approaches is used.
Use of consistent terminology (Figure 1.1) promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they can be equally applied to Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery and/or development.
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for incremental quantities within Contingent and Prospective Resources.
Without new technical information, there should be no change in the distribution of technically recoverable volumes and their categorization boundaries when conditions are satisfied sufficiently to reclassify a project from Contingent Resources to Reserves. All evaluations require application of a consistent set of forecast conditions, including assumed future costs and prices, for both classification of projects and categorization of estimated quantities recovered by each project (see Commercial Evaluations, section 3.1).
Based on additional data and updated interpretations that indicate increased certainty, portions of Possible and Probable Reserves may be re-categorized as Probable and Proved Reserves.
Uncertainty in resource estimates is best communicated by reporting a range of potential results. However, if it is required to report a single representative result, the "best estimate" is considered the most realistic assessment of recoverable quantities. It is generally considered to represent the sum of Proved and Probable estimates (2P) when using the deterministic scenario or the probabilistic assessment methods. It should be noted that under the deterministic incremental (risk-based) approach, discrete estimates are made for each category, and they should not be aggregated without due consideration of their associated risk (see "2001 Supplemental Guidelines," Chapter 2.5).
| Class/Sub-Class | Definition | Guidelines |
|---|---|---|
| Reserves | Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. |
Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. |
| A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. |
||
| To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests. |
||
| On Production | The development project is currently producing and selling petroleum to market. |
The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project "chance of commerciality" can be said to be 100%. |
| The project "decision gate" is the decision to initiate commercial production from the project. |
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
| Class/Sub-Class | Definition | Guidelines |
|---|---|---|
| Approved for Development |
All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way. |
At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity's current or following year's approved budget. |
| The project "decision gate" is the decision to start investing capital in the construction of production facilities and/or drilling development wells. |
||
| Justified for Development |
Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained. |
In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity's assumptions of future prices, costs, etc. ("forecast case") and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). |
| The project "decision gate" is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time. |
||
| Contingent Resources |
Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. |
Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. |
| Development Pending |
A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future. |
The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to "On Hold" or "Not Viable" status. |
| The project "decision gate" is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production. |
||
| Development Unclarified or on Hold |
A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay. |
The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to "Not Viable" status. |
| The project "decision gate" is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies. |
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
| Class/Sub-Class | Definition | Guidelines |
|---|---|---|
| Development Not Viable |
A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential. |
The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project "decision gate" is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future. |
| Prospective Resources |
Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. |
Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. |
| Prospect | A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. |
Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. |
| Lead | A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. |
Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. |
| Play | A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. |
Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios. |
| Status | Definition | Guidelines |
|---|---|---|
| Developed Reserves |
Developed Reserves are expected quantities to be recovered from existing wells and facilities. |
Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing. |
| Developed Producing Reserves |
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. |
Improved recovery reserves are considered producing only after the improved recovery project is in operation. |
| Developed Non Producing Reserves |
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. |
Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. |
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
| Status | Definition | Guidelines |
|---|---|---|
| Undeveloped Reserves |
Undeveloped Reserves are quantities expected to be recovered through future investments: |
(1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. |
| Category | Definition | Guidelines |
|---|---|---|
| Proved Reserves | Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a |
If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. |
| given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. |
The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data. |
|
| In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see "2001 Supplemental Guidelines," Chapter 8). |
||
| Reserves in undeveloped locations may be classified as Proved provided that: x The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. x Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. |
||
| For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program. |
||
| Probable Reserves |
Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered |
It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. |
| than Possible Reserves. | Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. |
|
| Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved. |
Excerpted from the Petroleum Resources Management System Approved by the Society of Petroleum Engineers (SPE) Board of Directors, March 2007
| Category | Definition | Guidelines |
|---|---|---|
| Possible Reserves |
Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves. |
The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with |
| (See above for separate criteria for | project recovery efficiencies beyond that assumed for Probable. The 2P and 3P estimates may be based on reasonable alternative |
|
| Probable and Possible Reserves |
Probable Reserves and Possible Reserves.) |
technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. |
| In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. |
||
| Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. |
||
| In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations. |
The 2007 Petroleum Resources Management System can be viewed in its entirety at http://www.spe.org/spe-app/spe/industry/reserves/prms.htm.
| ı ï l |
3 |
|---|---|
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF DECEMBER 31, 2012 ISOKO AND OGINI FIELDS
FIRST HYDROCARBON NIGERIA LTD. INTEREST
| PROVED (1P) RESERVES | OML 26, ONSHORE NIGERIA | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross (100 Percent) | Effective Working Interest | Net Entitlement Reserves | Gross Revenue to Net Interest | Cash Flow | ||||||||||
| Reserves Before Royalties | Reserves Before Royalties | After Royalties | After Royalties | Capital | Operating | Total PSC | Future Net | Discounted | ||||||
| Period | Oil | (1)Gas(1) | Oil | (1)Gas(1) | Oil | (1)Gas(1) | Oil | (12)Gas(1) | Total | Cost | Expense | Deducts | Revenue | at 10% |
| Ending | (MBBL) | (MMCF) | (MBBL) | (MMCF) | (MBBL) | (MMCF) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) |
| 12-31-2013 | 3,186.4 | 0.0 | 1,433.9 | 0.0 | 1,147.1 | 0.0 | 114,709.3 | 0.0 | 114,709.3 | 41,886.9 | 27,208.7 | 36,147.0 | 9,466.7 | 9,320.1 |
| 12-31-2014 | 3,444.1 | 0.0 | 1,549.9 | 0.0 | 1,239.9 | 0.0 | 123,989.2 | 0.0 | 123,989.2 | 44,900.1 | 28,730.7 | 43,966.2 | 6,392.2 | 16,051.1 |
| 12-31-2015 | 3,771.9 | 0.0 | 1,697.4 | 0.0 | 1,357.9 | 0.0 | 135,788.6 | 0.0 | 135,788.6 | 33,232.5 | 30,241.8 | 51,478.9 | 20,835.4 | 32,933.9 |
| 12-31-2016 | 4,245.4 | 0.0 | 1,910.5 | 0.0 | 1,528.4 | 0.0 | 152,836.0 | 0.0 | 152,836.0 | 72,922.5 | 32,435.8 | 39,482.7 | 7,995.0 | 38,501.7 |
| 12-31-2017 | 4,790.7 | 0.0 | 2,155.8 | 0.0 | 1,724.7 | 0.0 | 172,466.0 | 0.0 | 172,466.0 | 21,735.0 | 34,423.8 | 90,559.3 | 25,747.9 | 55,176.9 |
| 12-31-2018 | 4,449.6 | 0.0 | 2,002.3 | 0.0 | 1,601.9 | 0.0 | 160,186.7 | 0.0 | 160,186.7 | 5,490.0 | 33,624.0 | 90,642.6 | 30,430.2 | 73,359.7 |
| 12-31-2019 | 4,029.7 | 0.0 | 1,813.3 | 0.0 | 1,450.7 | 0.0 | 145,067.6 | 0.0 | 145,067.6 | 7,245.0 | 32,681.6 | 79,065.9 | 26,075.1 | 87,545.0 |
| 12-31-2020 | 3,643.2 | 0.0 | 1,639.5 | 0.0 | 1,311.6 | 0.0 | 131,156.6 | 0.0 | 131,156.6 | 0.0 | 31,410.8 | 75,265.4 | 24,480.5 | 99,573.8 |
| 12-31-2021 | 3,303.2 | 0.0 | 1,486.5 | 0.0 | 1,189.2 | 0.0 | 118,916.5 | 0.0 | 118,916.5 | 0.0 | 30,576.9 | 70,277.7 | 18,061.9 | 107,648.1 |
| 12-31-2022 | 2,980.9 | 0.0 | 1,341.4 | 0.0 | 1,073.1 | 0.0 | 107,313.0 | 0.0 | 107,313.0 | 0.0 | 29,130.8 | 64,454.0 | 13,728.1 | 113,232.5 |
| 12-31-2023 | 2,661.0 | 0.0 | 1,197.5 | 0.0 | 958.0 | 0.0 | 95,797.5 | 0.0 | 95,797.5 | 0.0 | 26,697.1 | 58,079.4 | 11,020.9 | 117,309.8 |
| 12-31-2024 | 2,420.4 | 0.0 | 1,089.2 | 0.0 | 871.3 | 0.0 | 87,134.0 | 0.0 | 87,134.0 | 0.0 | 26,084.6 | 52,031.7 | 9,017.7 | 120,344.7 |
| 12-31-2025 | 2,156.5 | 0.0 | 970.4 | 0.0 | 776.3 | 0.0 | 77,634.4 | 0.0 | 77,634.4 | 0.0 | 23,933.0 | 45,909.7 | 7,791.7 | 122,729.4 |
| 12-31-2026 | 1,937.7 | 0.0 | 872.0 | 0.0 | 697.6 | 0.0 | 69,758.6 | 0.0 | 69,758.6 | 0.0 | 22,455.8 | 40,445.6 | 6,857.2 | 124,637.0 |
| 12-31-2027 | 1,762.5 | 0.0 | 793.1 | 0.0 | 634.5 | 0.0 | 63,448.3 | 0.0 | 63,448.3 | 0.0 | 21,851.0 | 35,576.5 | 6,020.8 | 126,160.1 |
| Subtotal | 48,783.4 | 0.0 | 21,952.5 | 0.0 | 17,562.0 | 0.0 | 1,756,202.3 | 0.0 | 1,756,202.3 | 227,412.0 | 431,486.4 | 873,382.7 | 223,921.3 | 126,160.1 |
| Remaining | 8,911.1 | 0.0 | 4,010.0 | 0.0 | 3,208.0 | 0.0 | 320,799.6 | 0.0 | 320,799.6 | 0.0 | 174,291.5 | 125,627.4 | 20,880.7 | 129,956.1 |
| Total | 57,694.5 | 0.0 | 25,962.5 | 0.0 | 20,770.0 | 0.0 | 2,077,002.0 | 0.0 | 2,077,002.0 | 227,412.0 | 605,777.8 | 999,010.2 | 244,802.0 | 129,956.1 |
| Cum Prod | 75,869.4 | 62,383.6 | ||||||||||||
| Ultimate | 133,563.9 | 62,383.6 |
(1) No gas market exists for these properties; therefore, gas reserves have not been estimated for this report. BASED ON CONSTANT PRICE AND COST PARAMETERS
| l | I |
|---|---|
SUMMARY PROJECTION OF RESERVES AND REVENUE AS OF DECEMBER 31, 2012
FIRST HYDROCARBON NIGERIA LTD. INTEREST
ISOKO AND OGINI FIELDS OML 26, ONSHORE NIGERIA
| PROVED + PROBABLE (2P) RESERVES | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross (100 Percent) | Effective Working Interest | Net Entitlement Reserves | Gross Revenue to Net Interest | Cash Flow | ||||||||||
| Reserves Before Royalties | Reserves Before Royalties | After Royalties | After Royalties | Capital | Operating | Total PSC | Future Net | Discounted | ||||||
| Period | Oil | (1)Gas(1) | Oil | (1)Gas(1) | Oil | (1)Gas(1) | Oil | (12)Gas(1) | Total | Cost | Expense | Deducts | Revenue | at 10% |
| Ending | (MBBL) | (MMCF) | (MBBL) | (MMCF) | (MBBL) | (MMCF) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) |
| 12-31-2013 | 3,425.5 | 0.0 | 1,541.5 | 0.0 | 1,233.2 | 0.0 | 123,317.5 | 0.0 | 123,317.5 | 41,886.9 | 28,097.4 | 41,279.5 | 12,053.6 | 11,735.3 |
| 12-31-2014 | 4,491.2 | 0.0 | 2,021.0 | 0.0 | 1,616.8 | 0.0 | 161,683.5 | 0.0 | 161,683.5 | 78,650.1 | 32,203.5 | 48,026.1 | 2,803.7 | 14,718.6 |
| 12-31-2015 | 6,438.5 | 0.0 | 2,897.3 | 0.0 | 2,317.9 | 0.0 | 231,785.9 | 0.0 | 231,785.9 | 87,232.5 | 39,121.9 | 78,379.6 | 27,051.9 | 35,736.9 |
| 12-31-2016 | 8,340.9 | 0.0 | 3,753.4 | 0.0 | 3,002.7 | 0.0 | 300,272.9 | 0.0 | 300,272.9 | 93,172.5 | 45,954.4 | 121,421.5 | 39,724.4 | 63,951.0 |
| 12-31-2017 | 10,349.7 | 0.0 | 4,657.4 | 0.0 | 3,725.9 | 0.0 | 372,589.6 | 0.0 | 372,589.6 | 62,235.0 | 52,712.5 | 211,966.6 | 45,675.5 | 92,653.4 |
| 12-31-2018 | 10,231.7 | 0.0 | 4,604.3 | 0.0 | 3,683.4 | 0.0 | 368,340.1 | 0.0 | 368,340.1 | 5,490.0 | 53,294.2 | 245,240.6 | 64,315.4 | 130,990.7 |
| 12-31-2019 | 9,291.7 | 0.0 | 4,181.3 | 0.0 | 3,345.0 | 0.0 | 334,501.9 | 0.0 | 334,501.9 | 7,245.0 | 51,244.9 | 219,818.7 | 56,193.2 | 161,463.3 |
| 12-31-2020 | 8,426.4 | 0.0 | 3,791.9 | 0.0 | 3,033.5 | 0.0 | 303,352.1 | 0.0 | 303,352.1 | 0.0 | 48,804.5 | 204,372.4 | 50,175.2 | 186,127.7 |
| 12-31-2021 | 7,648.6 | 0.0 | 3,441.9 | 0.0 | 2,753.5 | 0.0 | 275,348.1 | 0.0 | 275,348.1 | 0.0 | 46,770.9 | 188,139.1 | 40,438.1 | 204,207.3 |
| 12-31-2022 | 6,939.5 | 0.0 | 3,122.8 | 0.0 | 2,498.2 | 0.0 | 249,821.5 | 0.0 | 249,821.5 | 0.0 | 44,638.9 | 172,502.1 | 32,680.5 | 217,498.5 |
| 12-31-2023 | 6,267.4 | 0.0 | 2,820.3 | 0.0 | 2,256.3 | 0.0 | 225,625.1 | 0.0 | 225,625.1 | 0.0 | 41,607.2 | 156,163.1 | 27,854.8 | 227,799.7 |
| 12-31-2024 | 5,694.4 | 0.0 | 2,562.5 | 0.0 | 2,050.0 | 0.0 | 204,999.9 | 0.0 | 204,999.9 | 0.0 | 40,020.5 | 140,739.4 | 24,240.0 | 235,951.1 |
| 12-31-2025 | 5,126.2 | 0.0 | 2,306.8 | 0.0 | 1,845.4 | 0.0 | 184,544.9 | 0.0 | 184,544.9 | 0.0 | 36,852.3 | 126,135.7 | 21,556.9 | 242,542.0 |
| 12-31-2026 | 4,644.1 | 0.0 | 2,089.8 | 0.0 | 1,671.9 | 0.0 | 167,185.9 | 0.0 | 167,185.9 | 0.0 | 34,910.8 | 112,976.9 | 19,298.2 | 247,905.7 |
| 12-31-2027 | 4,231.2 | 0.0 | 1,904.0 | 0.0 | 1,523.2 | 0.0 | 152,323.4 | 0.0 | 152,323.4 | 0.0 | 33,987.1 | 101,083.8 | 17,252.4 | 252,265.3 |
| Subtotal | 101,547.0 | 0.0 | 45,696.2 | 0.0 | 36,556.9 | 0.0 | 3,655,692.1 | 0.0 | 3,655,692.1 | 375,912.0 | 630,221.1 | 2,168,245.2 | 481,313.8 | 252,265.3 |
| Remaining | 33,034.0 | 0.0 | 14,865.3 | 0.0 | 11,892.3 | 0.0 | 1,189,225.4 | 0.0 | 1,189,225.4 | 0.0 | 464,583.1 | 620,090.8 | 104,551.5 | 268,756.3 |
| Total | 134,581.0 | 0.0 | 60,561.5 | 0.0 | 48,449.2 | 0.0 | 4,844,917.5 | 0.0 | 4,844,917.5 | 375,912.0 | 1,094,804.2 | 2,788,336.1 | 585,865.3 | 268,756.3 |
| Cum Prod | 76,048.9 | 62,383.6 | ||||||||||||
| Ultimate | 210,630.0 | 62,383.6 |
(1) No gas market exists for these properties; therefore, gas reserves have not been estimated for this report. BASED ON CONSTANT PRICE AND COST PARAMETERS
Table II
| ÿ | |
|---|---|
| ì ā ì ī J È |
J í j ì Ξ |
FIRST HYDROCARBON NIGERIA LTD. INTEREST
ISOKO AND OGINI FIELDS OML 26, ONSHORE NIGERIA
| PROVED + PROBABLE + POSSIBLE (3P) RESERVES | ||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross (100 Percent) | Effective Working Interest | Net Entitlement Reserves | Gross Revenue to Net Interest | Cash Flow | ||||||||||
| Reserves Before Royalties | Reserves Before Royalties | After Royalties | After Royalties | Capital | Operating | Total PSC | Future Net | Discounted | ||||||
| Period | Oil | (1)Gas(1) | Oil | (1)Gas(1) | Oil | (1)Gas(1) | Oil | (12)Gas(1) | Total | Cost | Expense | Deducts | Revenue | at 10% |
| Ending | (MBBL) | (MMCF) | (MBBL) | (MMCF) | (MBBL) | (MMCF) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) | (M\$) |
| 12-31-2013 | 3,656.9 | 0.0 | 1,645.6 | 0.0 | 1,316.5 | 0.0 | 131,647.2 | 0.0 | 131,647.2 | 41,886.9 | 28,952.9 | 46,249.0 | 14,558.4 | 14,072.6 |
| 12-31-2014 | 5,526.3 | 0.0 | 2,486.8 | 0.0 | 1,989.5 | 0.0 | 198,947.3 | 0.0 | 198,947.3 | 112,400.1 | 35,489.8 | 51,922.2 | (864.8) | 13,474.3 |
| 12-31-2015 | 9,030.9 | 0.0 | 4,063.9 | 0.0 | 3,251.1 | 0.0 | 325,114.2 | 0.0 | 325,114.2 | 120,982.5 | 47,281.5 | 115,193.1 | 41,657.1 | 45,907.2 |
| 12-31-2016 | 12,586.5 | 0.0 | 5,663.9 | 0.0 | 4,531.1 | 0.0 | 453,112.5 | 0.0 | 453,112.5 | 120,172.5 | 59,362.9 | 203,983.9 | 69,593.3 | 95,502.3 |
| 12-31-2017 | 15,437.7 | 0.0 | 6,946.9 | 0.0 | 5,557.6 | 0.0 | 555,755.7 | 0.0 | 555,755.7 | 62,235.0 | 69,212.0 | 350,180.0 | 74,128.7 | 142,742.9 |
| 12-31-2018 | 14,988.4 | 0.0 | 6,744.8 | 0.0 | 5,395.8 | 0.0 | 539,583.9 | 0.0 | 539,583.9 | 5,490.0 | 69,161.9 | 373,878.4 | 91,053.7 | 196,986.9 |
| 12-31-2019 | 13,613.5 | 0.0 | 6,126.1 | 0.0 | 4,900.8 | 0.0 | 490,084.9 | 0.0 | 490,084.9 | 7,245.0 | 65,969.2 | 337,216.6 | 79,654.2 | 240,149.6 |
| 12-31-2020 | 12,357.8 | 0.0 | 5,561.0 | 0.0 | 4,448.8 | 0.0 | 444,882.4 | 0.0 | 444,882.4 | 0.0 | 62,630.1 | 311,969.5 | 70,282.7 | 274,704.4 |
| 12-31-2021 | 11,223.8 | 0.0 | 5,050.7 | 0.0 | 4,040.6 | 0.0 | 404,057.5 | 0.0 | 404,057.5 | 0.0 | 59,804.4 | 286,631.9 | 57,621.3 | 300,470.0 |
| 12-31-2022 | 10,187.0 | 0.0 | 4,584.2 | 0.0 | 3,667.3 | 0.0 | 366,732.0 | 0.0 | 366,732.0 | 0.0 | 56,757.3 | 261,937.1 | 48,037.6 | 320,006.5 |
| 12-31-2023 | 9,221.0 | 0.0 | 4,149.5 | 0.0 | 3,319.6 | 0.0 | 331,956.2 | 0.0 | 331,956.2 | 0.0 | 53,024.0 | 237,169.8 | 41,762.4 | 335,449.4 |
| 12-31-2024 | 8,386.6 | 0.0 | 3,774.0 | 0.0 | 3,019.2 | 0.0 | 301,917.7 | 0.0 | 301,917.7 | 0.0 | 51,001.2 | 214,087.1 | 36,829.4 | 347,832.1 |
| 12-31-2025 | 7,571.0 | 0.0 | 3,406.9 | 0.0 | 2,725.6 | 0.0 | 272,555.7 | 0.0 | 272,555.7 | 0.0 | 47,106.0 | 192,503.1 | 32,946.5 | 357,903.1 |
| 12-31-2026 | 6,865.4 | 0.0 | 3,089.4 | 0.0 | 2,471.5 | 0.0 | 247,154.6 | 0.0 | 247,154.6 | 0.0 | 44,527.6 | 173,025.3 | 29,601.6 | 366,128.8 |
| 12-31-2027 | 6,251.6 | 0.0 | 2,813.2 | 0.0 | 2,250.6 | 0.0 | 225,057.7 | 0.0 | 225,057.7 | 0.0 | 43,094.9 | 155,393.7 | 26,569.1 | 372,841.3 |
| Subtotal | 146,904.4 | 0.0 | 66,107.0 | 0.0 | 52,885.6 | 0.0 | 5,288,559.5 | 0.0 | 5,288,559.5 | 470,412.0 | 793,375.6 | 3,311,340.7 | 713,431.2 | 372,841.3 |
| Remaining | 51,689.7 | 0.0 | 23,260.4 | 0.0 | 18,608.3 | 0.0 | 1,860,829.1 | 0.0 | 1,860,829.1 | 0.0 | 637,069.0 | 1,046,516.1 | 177,244.1 | 399,746.3 |
| Total | 198,594.1 | 0.0 | 89,367.4 | 0.0 | 71,493.9 | 0.0 | 7,149,388.6 | 0.0 | 7,149,388.6 | 470,412.0 | 1,430,444.5 | 4,357,856.8 | 890,675.3 | 399,746.3 |
| Cum Prod | 76,222.5 | 62,383.6 | ||||||||||||
| Ultimate | 274,816.6 | 62,383.6 |
(1) No gas market exists for these properties; therefore, gas reserves have not been estimated for this report. BASED ON CONSTANT PRICE AND COST PARAMETERS
The Company and the Directors, whose names appear on page 74 of this Document, accept responsibility for the information contained in this Document. To the best of the knowledge and belief of the Company and the Directors, (who have taken all reasonable care to ensure that such is the case) the information contained in this Document is in accordance with the facts and does not omit anything likely to affect the import of such information.
NSAI, whose registered address is at 4500 Thanksgiving Tower, 1601 Elm Street, Dallas, Texas 75201-4754, United States, accepts responsibility for the NSAI Report set out in Part 7 of this Document. To the best of the knowledge and belief of NSAI (which has taken all reasonable care to ensure that such is the case) the information contained therein is in accordance with the facts and does not omit anything likely to affect the import of such information.
The Company is of the opinion that, taking account of existing cash resources and other existing facilities available to the Enlarged Group, the Enlarged Group has sufficient working capital for its present requirements, that is, for at least the 12 months following the date of the publication of this Document.
There has been no significant change in the financial or trading position of the Group since 31 December 2012, being the date to which the latest audited financial information of the Company has been prepared.
There has been no significant change in the financial or trading position of FHN since 31 December 2012, being the date to which the latest audited financial information of FHN has been prepared.
4.1 The Directors of the Company are:
Mr. Egbert Imomoh (Non-Executive Chairman) Dr. Osman Shahenshah (Chief Executive) Mr. Shahid Ullah (Chief Operating Officer) Mr. Darra Comyn (Group Finance Director) Mr. Ennio Sganzerla (Non Executive Director) Mr. Peter Bingham (Non Executive Director) Mr. John St. John (Non Executive Director) Mr. Toby Hayward (Non Executive Director) Mr. Patrick Obath (Non-Executive Director)
4.2 The business address of each of the Directors is:
Afren plc Kinnaird House 1 Pall Mall East London SWI Y 5AU
As at 30 April 2013 (being the last practicable date prior to publication of this Document), the interests of the Directors in the share capital of the Company (all of which are beneficial unless otherwise stated) which have been notified to the Company pursuant to the Disclosure and Transparency Rules are set out below:
| Percentage of | ||
|---|---|---|
| Number of | issued number of | |
| Name of Director | Ordinary Shares | Ordinary Shares |
| Egbert Imomoh | 3,972,246 | 0.36% |
| Osman Shahenshah | 4,895,856 | 0.45% |
| Shahid Ullah | 4,360,106 | 0.40% |
| Darra Comyn | – | – |
| Peter Bingham | – | – |
| Toby Hayward | 205,000 | 0.02% |
| Ennio Sganzerla | 24,000 | 0.00% |
| John St. John | 177,823 | 0.02% |
| Patrick Obath | – | – |
The Share Option scheme was adopted before the Company's shares were admitted to the Official List. It is now the Remuneration Committee's current policy to grant options under this scheme only in exceptional circumstances for recruitment purposes and for rewarding significant promotions, including to Executive Director.
As at 30 April 2013 (being the last practicable date prior to publication of this Document), the following Ordinary Shares have been granted to Directors under the Afren 2005 Share Option Scheme:
| Share price at | Exercisable | ||||
|---|---|---|---|---|---|
| Name of Director | Number | grant date | Exercise price | from | Exercisable to |
| E Imomoh | 400,000 | 36p | 20p 28.06.05–01.03.07 | 27.06.15 | |
| 500,000 | 36p | 50p 28.06.05–01.03.06 | 27.06.15 | ||
| 500,000 | 36p | 100p 28.06.05–01.03.07 | 27.06.15 | ||
| 600,000 | 63p | 63p 30.05.07–30.05.09 | 29.05.16 | ||
| 250,000 | 53.5p | 80p 28.03.07–28.03.10 | 27.03.17 | ||
| 250,000 | 53.5p | 120p 28.03.07–28.03.10 | 27.03.17 | ||
| 250,000 | 53.5p | 180p 28.03.07–28.03.10 | 27.03.17 | ||
| 750,000 | 20.25p | 23.25p 23.01.10–23.01.12 | 23.01.19 | ||
| O Shahenshah | 1,150,000 | 36p | 20p 28.06.05–01.03.07 | 27.06.15 | |
| 850,000 | 36p | 50p 28.06.05–01.03.06 | 27.06.15 | ||
| 550,000 | 36p | 100p 28.06.05–01.03.07 | 27.06.15 | ||
| 600,000 | 63p | 63p 30.05.07–30.05.09 | 29.05.16 | ||
| 416,666 | 53.5p | 80p 28.03.07–28.03.10 | 27.03.17 | ||
| 416,667 | 53.5p | 120p 28.03.07–28.03.10 | 27.03.17 | ||
| 416,667 | 53.5p | 180p 28.03.07–28.03.10 | 27.03.17 | ||
| 3,000,000 | 20.25p | 23.25p 23.01.10–23.01.12 | 23.01.19 | ||
| 5,800,000 | 84.75p | 84.75p 30.12.10–30.12.12 | 30.12.19 | ||
| S Ullah | 1,500,000 | 20.25p | 23.25p 23.01.10–23.01.12 | 23.01.19 | |
| 1,500,000 | 84.75p | 84.75p 30.12.10–30.12.12 | 30.12.19 |
| Share price at | Exercisable | ||||
|---|---|---|---|---|---|
| Name of Director | Number | grant date | Exercise price | from | Exercisable to |
| D Comyn | 650,000 | 84.75p | 84.75p 30.12.10–30.12.12 | 30.12.19 | |
| 1,200,000 | 103p | 103p 29.03.11–29.03.13 | 28.03.20 | ||
| P Bingham | 125,000 | 36p | 50p 28.06.05–01.03.06 | 27.06.15 | |
| 130,000 | 36p | 100p 28.06.05–01.03.07 | 27.06.15 | ||
| 145,000 | 69p | 70p 21.06.07–21.06.08 | 20.06.17 | ||
| J St. John | 400,000 | 69p | 70p 21.06.07–21.06.09 | 20.06.17 | |
| Total | ––––––––––– 28,350,000 |
||||
| ––––––––––– |
The Share Option Scheme Rules have been amended to prohibit the grant of share options to Non-Executive Directors.
The Company operates the Afren 2008 Performance Share Plan as part of its incentive arrangements. The Performance Share Plan ("PSP") was introduced in 2008 before the Company's shares were admitted to the Official List.
Under the PSP, eligible employees, including Directors, who have been selected to participate, receive an award of shares in the Company. Share awards may be made annually and the maximum value of an award for any Director may not exceed 200% of base annual salary, except that the Remuneration Committee may decide to increase this limit to 300% in exceptional circumstances. The awards are subject to achieving or exceeding the performance criteria set out for the individuals.
Ordinarily, an award, normally in the form of a conditional share award or a nominal cost share option, vests three years after the award date subject to the Company's Total Shareholder Return ("TSR") performance relative to the TSR of a selected peer group of companies. An award may vest in full only if Afren's position in the peer group is at or above the 75th percentile. 30% of an award vests for median performance and nothing vests if Afren's TSR is below the median. There is pro rata vesting for performance between the median and upper quartile.
As at 30 April 2013 (being the latest practicable date prior to the publication of this Document), the following Directors held the following interests in Ordinary Share of the company under the PSP:
| Date of award |
Date of vesting |
As at 1 January 2012 |
Granted | Vested | Lapsed | As at 31 December 2012 |
Market price at date of award |
Market price at date of vesting |
|
|---|---|---|---|---|---|---|---|---|---|
| Osman | |||||||||
| Shahenshah | 19.06.2009 | 19.06.2012 | 1,526,012 | – | 1,258,959 | 267,053 | – | £0.43 | £1.07 |
| 31.03.2011 | 31.03.2014 | 788,644 | – | – | – | 788,644 | £1.63 | ||
| 29.06.2012 | 29.06.2015 | – | 1,302,083 | – | – | 1,302,083 | £1.04 | ||
| Darra Comyn | 31.03.2011 | 31.03.2014 | 473,186 | – | – | – | 473,186 | £1.63 | |
| 29.06.2012 | 29.06.2015 | – | 781,250 | – | – | 781,250 | £1.04 | ||
| Shahid Ullah | 19.06.2009 | 19.06.2012 | 1,322,600 | – | 1,091,145 | 231,455 | – | £0.43 | £1.07 |
| 31.03.2011 | 31.03.2014 | 530,048 | – | – | – | 530,048 | £1.63 | ||
| 29.06.2012 | 29.06.2015 | – | 838,844 | – | – | 838,844 | £1.04 | ||
Awards to Directors granted under the PSP are as follows:
2009 Grant: The performance measure was three-year relative total shareholder return against a benchmark of 14 peer upstream oil and gas companies with significant interest in Africa.
Shares would vest in full if Afren achieved top quartile performance. 30% vested at the threshold of median performance, with straight-line vesting between. Afren achieved a ranking of 4th over the three years, and 82.5% of the grant vested.
2012 Grant: Relative total shareholder return is measured against a 22 company E&P peer group (70%) and the FTSE 250 (30%) with similar 30% to 100% vesting. There is an underpinning requirement for vesting based on the reserves replacement ratio over the three-year period.
As at 30 April 2013 (being the last practicable date prior to publication of this Document), the Company has been notified of the following interests of the Directors in the share capital of FHN (all of which are beneficial unless otherwise stated):
| Percentage of | |||
|---|---|---|---|
| Number of | issued number of | ||
| Name of Director | FHN shares | FHN shares | |
| Egbert Imomoh | 4,524,756 | 3.1% | |
| Osman Shahenshah | 2,951,793 | 2.0% | |
| Shahid Ullah | 953,846 | 0.7% | |
| Darra Comyn | 1,499,400 | 1.0% | |
| Peter Bingham | – | – | |
| Toby Hayward | – | – | |
| Ennio Sganzerla | – | – | |
| John St. John | – | – | |
| Patrick Obath | – | – |
The aggregate holdings of FHN shares by Afren PDMRs represents approximately 9.8% of FHN's fully diluted share capital.
6.1 As of 30 April 2013 (being the latest practicable date prior to publication of this Document), interests notified to the Company in accordance with Chapter 5 of the Disclosure and Transparency Rules comprised:
| Approximate percentage |
|---|
| of voting rights |
| 8.28% |
| 8.01% |
| 5.01% |
| 4.97% |
| 4.94% |
| 4.93% |
| 4.49% |
| 3.60% |
| 3.01% |
| 3.01% |
Percentages are based on the issued share capital at the date of notification.
6.2 Save as disclosed in this paragraph 6, the Company is not aware of any person who as at 30 April 2013 (the latest practicable date prior to the publication of this Document) was interested directly or indirectly (within the meaning of Rule 5 of the Disclosure and Transparency Rules) which will represent 3% or more of the total voting rights in the Company. The Company is not aware of any person who, directly or indirectly owns or controls the Company.
7.1 It is the Company's policy that Executive Directors should have contracts of an indefinite term providing for a maximum of one year's notice. The Directors have no entitlement to any bonus or other additional payment on severance of their contract. Each Director would be considered on an individual basis and any payment would be entirely at the Company's discretion. The details of the Directors' contracts are summarised below.
| Name of Director | Office | Date of contract | Notice period |
|---|---|---|---|
| Executive | |||
| Osman Shahenshah | Chief Executive Officer | 27.02.2009 | 12 months |
| Shahid Ullah | Chief Operating Officer | 16.04.2008 | 6 months |
| Darra Comyn | Group Finance Director | 16.03.2010 | 12 months |
| Non-executive | |||
| Egbert Imomoh | Chairman | 01.09.2009 | 3 months |
| Peter Bingham | Non-Executive | 10.05.2005 | 3 months |
| John St. John | Non-Executive | 18.06.2007 | 3 months |
| Toby Hayward | Non-Executive | 26.06.2009 | 3 months |
| Ennio Sganzeria | Non-Executive | 26.06.2009 | 3 months |
| Patrick Obath | Non-Executive | 02.02.2012 | 3 months |
| Total | LTI Awards | Total | ||||||
|---|---|---|---|---|---|---|---|---|
| Fees/basic | Benefits | Total | emoluments | Pension | vesting remuneration | |||
| salary | in kind | Allowance | bonus | 2012 contributions | in year* | 2012 | ||
| (£'000) | (£'000) | (£'000) | (£'000) | (£'000) | (£'000) | (£'000) | (£'000) | |
| Executive Directors | ||||||||
| Osman Shahenshah | 625 | 26 | – | 1,275 | 1,926 | 92 | 1,347 | 3,365 |
| Shahid Ullah | 424 | 19 | – | 939 | 1,382 | 16 | 1,168 | 2,566 |
| Darra Comyn | 375 –––––––– |
8 –––––––– |
– –––––––– –––––––– |
727 | 1,110 –––––––– |
43 –––––––– |
– –––––––– |
1,153 –––––––– |
| 1,424 | 53 | – | 2,941 | 4,418 | 151 | 2,515 | 7,084 | |
| Non-executive | –––––––– | –––––––– | –––––––– –––––––– | –––––––– | –––––––– | –––––––– | –––––––– | |
| Directors | ||||||||
| Egbert Imomoh | 200 | 2 | 46 | – | 248 | – | – | 248 |
| Peter Bingham | 60 | – | – | – | 60 | – | – | 60 |
| John St. John | 55 | – | – | – | 55 | – | – | 55 |
| Toby Hayward | 70 | – | – | – | 70 | – | – | 70 |
| Ennio Sganzeria | 51 | – | – | – | 51 | – | – | 51 |
| Patrick Obath | 47 –––––––– |
– –––––––– |
– –––––––– –––––––– |
– | 47 –––––––– |
– –––––––– |
– –––––––– |
47 –––––––– |
| 483 | 2 | 46 | – | 531 | – | – | 531 | |
| –––––––– | –––––––– | –––––––– –––––––– | –––––––– | –––––––– | –––––––– | –––––––– |
7.3 It is the Company's policy that Executive Directors should have contracts of an indefinite term providing for a maximum of one year's notice. The Directors have no entitlement to any bonus or other additional payment on severance of their contract. Directors are considered on an individual basis and any payment is entirely at the Company's discretion.
FHN, an associate of Afren plc, has an outstanding payable to Afren of US\$9.6 million at 30 April 2013 (the latest practicable date prior to the publication of this Document).
Further details regarding related party transactions between FHN and Afren are set out in Note 27 to FHN's 2012 audited financials statements in Part 5 of this Document.
Further details regarding related party transactions for Afren are set out in Note 35 to the Company's 2012 audited financials statements.
9.1.1 The Initial Deed and the Deed of Variation in respect of the Acquisition, details of which are set out in Part 4 of this Document.
The following is a summary of each contract (not being a contract entered into in the ordinary course of business): (a) to which FHN or any member of the FHN group is or has been a party within the two years immediately preceding the date of this document which is, or may be material; or (b) that has been entered into by FHN or any member of the FHN group and which contains any provisions under which any member of the FHN group has any obligation or entitlement which is material to the FHN group as at the date of this document.
On 20 October 2010, SPDC, TOTAL and NAOC entered into an assignment agreement with FHN 26 in respect of transferring their entire participating interest in OML 26 to FHN 26, subject to certain conditions (the "Assignment Agreement").
Under the Assignment Agreement, SPDC, TOTAL and NAOC agreed to transfer to FHN 26 their 45% undivided participating interest in the Original JOA comprising of: SPDC, 30%, TOTAL, 10% and NAOC, 5%, together with the rights and obligations, and interests related thereto, those being: OML 26 and associated property subject to the assignment.
The total consideration for the transfer under the Assignment Agreement was US\$147,500,000 to be split pro rata between SPDC, TOTAL and NAOC in accordance with their respective percentage interests. FHN 26 agreed to certain obligations regarding the employees of SPDC for a period of 24 months following completion.
The warranties covered by the Assignment Agreement are those usually expected in an agreement of this type, including warranties in relation to: incorporation and capacity, no default, filings and consents, litigation, data and information, insolvency, ownership of interests being transferred, compliance, insurance and financial strength of FHN 26, amongst others. FHN 26 indemnified SPDC, TOTAL and NAOC for all decommissioning liabilities, environmental liabilities and post-completion liabilities (including post-completion tax liabilities) in their respective percentage interests. The Assignment Agreement does not extend to granting any right, title or interest in any intellectual property linked to those assets transferred to FHN 26 and FHN 26 did not receive rights to any of the SPDC, TOTAL or NAOC manuals or policy documents.
On 1 December 2011, NNPC, SPDC, NAOC and TOTAL entered into a joint operating agreement governing their obligations and the joint operations in respect of Oil Mining Lease 26 ("OML 26") (the "JOA").
The JOA adopted the terms of the joint operating agreement entered into between NNPC, NAOC, TOTAL and SPDC on 11 July 1991 (the "Original JOA") in their entirety, with the exception that the terms only apply in respect of OML 26 rather than the expanded list of oil mining leases as set out in the Original JOA.
On 11 November 2011, FHN 26 entered into a US\$230m loan facility with FCB Capital Markets Limited and Stanbic IBTC Bank PLC. FHN acted as guarantor to FHN 26 under the facility agreement. The facility comprises two parts, a term loan acquisition tranche (Tranche A) and a revolving borrowing base tranche (Tranche B). Both tranches are to be used solely in respect of the acquisition and development of OML 26. In the year ended 31 December 2011, FHN 26 drew down US\$108 million of Tranche A to fund the completion of the OML 26 acquisition. There has been no drawdown under Tranche B to date. The facility is for a 5 year term and interest on the facility is based on LIBOR plus 8.5%. The commitments under Tranche A began reducing in 2012, when a repayment of US\$6.75 million was made on 31 December 2012. The remainder of the loan facility is to be repaid in instalments by FHN 26 on set repayment dates.
On 19 September 2011, FHN issued a six year US\$50 million senior unsecured unsubordinated convertible note to fund the development activities of the FHN group. The convertible loan notes were subsequently fully subscribed to by Pan African Investment Partners II who holds the option to convert this loan note to approximately 27,000,000 FHN shares at a conversion price of US\$1.85 per FHN share. The net proceeds from the issue of the loan notes were split between a liability component and an equity component at the date of issue. On issue, the liability component of the loan notes was US\$45.7 million, with the equity component of US\$4.2 million.
On 14 November 2011, FHN 26 entered into ISDA master agreements with FCMB and Standard Bank plc in respect of deferred premium put options relating to production from the OML 26 field. FHN 26 will receive a minimum amount if the market price of oil falls. These hedges are over a three year period from 1 January 2012 to 31 December 2014 and a total premium of US\$54.7 million will be expensed by FHN 26 over this period. The maximum crude oil price protected is between US\$90 and US\$100/bbl (with a weighted average of US\$94.38/bbl over the period) with a US\$65/bbl floor which is intended to ensure that the required repayments on the acquisition and development loan facility with FCB Capital Markets Limited and Stanbic IBTC Bank PLC referred to this paragraph 9.2.3 are met.
FHN and SPDC entered into a crude handling agreement on 20 October 2010 (the "Crude Handling Agreement") setting out the terms on which SPDC would provide services to FHN in respect of crude handling. The term of the Crude Handling Agreement is five years from 1 December 2011 although this is subject to renewal or extension with the consent of both FHN and SPDC.
The services provided by SPDC under the Crude Handling Agreement consist of: (i) acceptance of crude oil (mineral oil in its natural state before it has been refined or treated) as may be delivered by FHN; (ii) the transportation of FHN crude oil (crude oil produced by FHN); (iii) treatment, processing and storage of FHN crude oil received in the SPDC terminal (the onshore terminal belonging to the joint venture between NNPC, SPDC, TOTAL and NAOC at Forcados in Delta State of Nigeria); and (iv) the redelivery to FHN of dry crude available for delivery to tankers at the SPDC terminal.
In consideration for the performance of the crude handling services, FHN has agreed to pay SPDC a capacity charge and a production charge. The capacity charge and production charge both apply when the SPDC terminal is used but the rates vary depending on the properties of the crude oil. Where the crude oil consists only of dry crude (crude oil with a water content of less than 0.5% by volume) for that given month the capacity charge is US\$1.46 per barrel and the production charge is US\$0.12 per barrel; however, where the crude oil consists of wet crude (crude oil with a water content of 0.5% or more by volume) on any given day in a month, FHN is required to pay a capacity charge of US\$1.58 per barrel and a production charge of US\$0.22. The capacity charge and production charge also apply on a similar basis where the SPDC pipeline system is used with the capacity charge being set at either at US\$0.85 or US\$0.65 and the production charge being set either at US\$0.44 or US\$0.32. These charges, however, are subject to reductions and/or increases in certain situations such as force majeure and where the volume of oil exceeds a certain quantity; FHN and SPDC also agreed that these charges are subject to annual review in consideration of general price changes in the market.
A corporate services agreement was entered into between FHN and Afren Energy Services Limited ("Afren Energy") a subsidiary of Afren, on 20 September 2012 (the "Corporate Services Agreement") setting out the terms and conditions under which Afren Energy would provide FHN with know-how, experience and technical advice in respect of oil licences (and their related assets) and the necessary skill and expertise required to operate such assets.
The term of the Corporate Services Agreement is five years, although this is subject to renewal or extension with the consent of both parties. Under the terms of the Corporate Services Agreement, Afren Energy is required to provide FHN with a range of services including financial, accountancy, tax, business development, operation and internal control services and any other ancillary services which FHN may reasonably request from time to time. Afren Energy also provides FHN with know-how and experience with respect to the development and commercial exploitation of FHN's acquisition of an interest or license permitting FHN to explore, develop or operate an area containing any mineral, oil or natural gas. These services do not require Afren Energy to include FHN as a subsidiary in its accounts and are subject to annual review by FHN and Afren Energy. If it seems that the provision of any of the services will render FHN as a subsidiary of Afren Energy, Afren Energy is permitted to cease such provision immediately.
In return for the services provided by Afren Energy, FHN pays Afren Energy (i) an operating fee, which is an annual flat fee equivalent to 2.25% of operating revenues of OML 26 and (ii) a sponsor's fee equivalent to 5% of operating revenues of OML 26 for the life of OML 26. If FHN acquires an additional petroleum asset or investment, Afren Energy and FHN will negotiate an operating fee, if applicable, with respect to such new petroleum asset or interest.
Afren Energy remains responsible for the salaries and expenses of staff seconded from Afren Energy to FHN prior to entering into the Corporate Services Agreement, unless otherwise agreed in writing by FHN and Afren Energy. If it is agreed that FHN is to reimburse Afren Energy for expenses in connection with seconded staff, FHN will make such payments within 30 days of receipt of Afren Energy's invoice of payment.
Save as set out below, there are no governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Company is aware) during the 12 months proceeding the date of this Document, which may have, or have had in the recent past, a significant effect on the Company and/or the Group's financial position or profitability.
Save as set out below, there are no governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Company is aware) during the 12 months proceeding the date of this Document, which may have, or have had in the recent past, a significant effect on FHN's and/or the FHN group's financial position or profitability.
On 18 May 2012 a writ of summons was issued by various individual claimants, for themselves and on behalf of (inter alia) the Isoko National Youth Movement and the Iyede Ame community, against Afren Group plc, FHN, SPDC, NPDC, NNPC and the Minister of Petroleum Resources. The writ alleged that the acquisition of onshore facilities, including OML 26 and OML30, required the prior consent of the claimants and was therefore illegal, null and void. The claimants sought a court order setting aside the sale, damages amounting to N=2,000,000,000, and an order granting them 10% of the daily oil production quantum from the defendants. On 15 June 2012, Afren and FHN applied for an order striking out the writ of summons and dismissing the suit and the proceedings have been adjourned to May 2013. Afren has been advised and strongly believes the case is completely without merit.
Certain information has been obtained from external publications and is sourced in this Document where the information is included. Where information has been sourced from a third party, the Company confirms that this information has been accurately reproduced and that as far as the Company is aware and is able to ascertain from information published by that third party, no facts have been omitted which would render the reproduced information inaccurate or misleading. Unless otherwise stated, such information has not been audited.
Any financial information extracted from FHN's audited financial statements has been extracted without material adjustment.
NSAI has given and has not withdrawn its written consent to the inclusion of the NSAI Report in Part 7 of this Document and/or extracts therefrom and the references thereto and to its name in the form and context in which they appear.
Deloitte has given and has not withdrawn its written consent to the inclusion of its reports in Part 5 and Part 6 of this document in the form and context in which they appear.
Merrill Lynch International has given and has not withdrawn its written consent to the inclusion in this Document of references to its name in the form and context in which they appear.
Copies of the following documents may be inspected at the registered office of the Company during usual business hours on any weekday (Saturdays, Sundays and public holidays excepted) from the date of this Document up to and including the date of Admission:
Dated: 2 May 2013.
The following definitions apply throughout this Circular, unless the context otherwise requires:
| "Acquisition" | the acquisition of the beneficial interest in 10.4% of the issued share capital of FHN by Afren pursuant to the terms of and subject to the conditions in the Agreement |
|---|---|
| "Afren" | Afren plc |
| "Afren Shareholders" | holders of Ordinary Shares |
| "Agreement" | the put option deed dated 4 April 2011, as amended on 25 March 2013, between Afren and COGIL setting out the terms and conditions of, and the arrangements for the implementation of the Acquisition, summarised in Part 4 of this Circular |
| "Board" | the board of directors of Afren from time to time including a duly constituted committee thereof |
| "COGIL" | CBO Oil and Gas FHN Investment Services Vehicle Limited (formerly Honics Investment Services Limited), a private company incorporated under the laws of the Federal Republic of Nigeria |
| "COGIL Loan" | A US\$33 million term loan facility from FCMB to COGIL in 2011 to finance COGIL's acquisition of the Option Shares |
| "Circular" or "Document" | this document |
| "Company" or "Afren" | Afren plc |
| "Condition" | the condition precedent to completion of the Acquisition, being receipt of all necessary approvals of Shareholders at the General Meeting to the acquisition of the Option Shares |
| "CREST" | the relevant system (as defined in the Uncertified Securities Regulations 2001 (SI 2001 No. 3755) operated by CRESTCo Limited |
| "Deed of Variation" | the deed of variation dated 25 March 2013 between Afren and COGIL in respect of the Initial Deed |
| "Deloitte" | Deloitte LLP |
| "Directors" | the directors of Afren, whose names are set out on page 74 of this Circular |
| "Enlarged Group" | the Group (including FHN) following completion of the Acquisition |
| "FCA" | the UK Financial Conduct Authority |
| "FCMB" | First City Monument Bank Plc |
| "FHN" | First Hydrocarbon Nigeria Company Limited |
| "FHN 26" | FHN 26 Limited |
| "FSMA" | the Financial Services and Markets Act 2000, as amended |
|---|---|
| "GBP" or "£" | pound sterling |
| "General Meeting" | the general meeting convened for 2.30 p.m. on 20 May 2013 to approve the Acquisition to which this Circulate relates |
| "Group" | Afren and its subsidiary undertakings from time to time |
| "IFRS" | International Financial Reporting Standards as adopted by the European Union |
| "Initial Deed" | the put option deed dated 4 April 2011 between Afren and COGIL in respect of the grant by Afren of the put option over the Option Shares |
| "Listing Rules" | the rules and regulations made by the UK Listing Authority pursuant to Part VI FSMA, as amended from time to time |
| "London Stock Exchange" | London Stock Exchange plc |
| "Merrill Lynch International" | Merrill Lynch International, which is authorised and regulated in the United Kingdom by the FCA and is a member of the London Stock Exchange, acting as sponsor to the Company |
| "Naira" or "N=" | the Naira, the official currency of the Federal Republic of Nigeria |
| "NAOC" | Nigerian Agip Oil Company Limited |
| "NNPC" | The Nigerian National Petroleum Corporation |
| "NPDC" | The Nigerian Petroleum Development Corporation |
| "NSAI" | Netherland, Sewell & Associates, Inc. |
| "NSAI Report" | the report by NSAI on OML 26 set out in Part 7 of this Circular |
| "Official List" | the Official List of the UK Listing Authority |
| "OML 26" | Oil Mining Lease 26 in Nigeria |
| "Option" | The put option in respect of the Option Shares granted by Afren to COGIL pursuant to the Agreement |
| "Option Shares" | the 15,000,000 ordinary shares of N=1.00 each in FHN which are subject to the Agreement |
| "Ordinary Shares" | the ordinary shares of one penny each in the capital of Afren |
| "p" | pence |
| "PDMRs" | persons discharging managerial responsibility |
| "Regulations" | the Uncertificated Securities Regulations 2001 (including any modification, re enactment or substitute regulations for the time being in force) |
| "Shareholder" | a holder of Ordinary Shares |
| "Side Agreement" | the agreement dated 25 March 2013 between Afren, FCMB and COGIL in respect of, inter alia, certain indebtedness owed by COGIL to FCMB |
| "SPDC" | The Shell Petroleum Development Company of Nigeria Limited |
|---|---|
| "TOTAL" | Total E&P Nigeria Limited |
| "Trust Deed" | the trust deed dated 2 May 2013 between the Trustee and the Company |
| "Trustee" | Adcax Investments Limited |
| "UK" | the United Kingdom of Great Britain and Northern Ireland |
| "UK Listing Authority" | the Financial Conduct Authority acting in its capacity as the competent authority for the purposes of Part VI of FSMA |
| "United States" or "US" | United States of America |
| "US\$" or "\$" or "USD" | US dollars |
(Incorporated in England and Wales with Registered No. 05304498)
NOTICE IS HEREBY GIVEN that an General Meeting of the Company will be held at 2.30 p.m. on 20 May 2013 at the offices of White & Case LLP, 5 Old Broad Street, London EC2N 1DW, United Kingdom ("Notice") for the purposes of considering and, if thought fit, passing the following Resolution:
the proposed acquisition ("Acquisition") of the beneficial interest in 15,000,000 ordinary shares in the capital of First Hydrocarbon Nigeria Company Limited ("FHN") (the "Option Shares") from CBO Oil and Gas FHN Investment Services Vehicle Limited ("COGIL") to be effected pursuant to the put option agreement between Afren and COGIL, substantially on the terms and subject to the conditions summarised in Part 4 of the circular to shareholders of the Company dated 2 May 2013 ("Circular") outlining the Acquisition (a copy of which is produced to the meeting and signed for identification purposes by the chairman of the meeting), be approved and the Directors (or any duly constituted committee thereof) ("Board") be authorised (1) to take all such steps as the Board considers to be necessary or desirable in connection with, and to implement, the Acquisition; and (2) to agree such non-material modifications, variations, revisions, waivers, extensions or amendments to any of the terms and conditions of the Acquisition, and/or to any documents relating thereto, as they may in their absolute discretion think fit.
Dated 2 May 2013
1 Pall Mall East Joint Company Secretary London SW1Y 5AU
Registered office: By Order of the Board Kinnaird House Elekwachi Ukwu
Company. A proxy form which may be used to make such appointment and give proxy instructions accompanies this notice. If you do not have a proxy form and believe that you should have one, or if you require additional forms, please contact the Company's registrars, Computershare Investor Services PLC, The Pavilions, Bridgwater Road, Bristol, BS99 6ZY.
already held by the Chairman, result in the Chairman holding such number of voting rights that he has a notifiable obligation under the Disclosure and Transparency Rules, the Chairman will make the necessary notifications to the Company and the Financial Conduct Authority. As a result, any member holding 3% or more of the voting rights in the Company who grants the Chairman a discretionary proxy in respect of some or all of those voting rights and so would otherwise have a notification obligation under the Disclosure and Transparency Rules, need not make a separate notification to the Company and the Financial Conduct Authority.
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