HERITAGE OIL LIMITED

Transcription

1 This document comprises a prospectus relating to Heritage Oil Limited (the Company and, together with its subsidiaries, the Group ) prepared in accordance with the Prospectus Rules made under section 73A of the Financial Services and Markets Act 2000 (the FSMA ). This document will be made available to the public in accordance with the Prospectus Rules. The Company and its Directors (whose names appear on page 27 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 contains no omission likely to affect its import. Application has been made to the Financial Services Authority for all of the Ordinary Shares and Exchangeable Shares to be admitted to listing on the Official List and to the London Stock Exchange plc for such Ordinary Shares and Exchangeable Shares to be admitted to trading on the London Stock Exchange s main market for listed securities. Admission to the Official List together with admission to trading on the London Stock Exchange s main market for listed securities (together Admission ) will constitute admission to listing on a regulated market. It is expected that Admission will become effective and that unconditional dealings on the London Stock Exchange will commence in the Ordinary Shares at 8.00 a.m. on 31 March 2008 with ISIN JE00B2Q4TN56 and will commence in the Exchangeable Shares at 8.00 a.m. on 2 April 2008 with ISIN CA For a discussion of certain risk and other factors that should be considered in connection with an investment in the Ordinary Shares or Exchangeable Shares, see the Risk Factors section of this document. HERITAGE OIL LIMITED (Incorporated in Jersey under the Companies (Jersey) Law 1991, as amended, with registered number 99922) Admission to the Official List and to trading on the London Stock Exchange Sponsor JPMorgan Cazenove Expected share capital immediately following Admission Authorised Issued and Fully Paid Unlimited Ordinary Shares of no par value 250,513,032 1 Special Voting Share of no par value 1 Unlimited Exchangeable Shares of no par value (1) 4,431,120 (1) The Exchangeable Shares will be issued by Heritage Oil Corporation ( HOC, which will be at the time of Admission an indirect, wholly-owned subsidiary of the Company) in connection with the Plan of Arrangement described elsewhere in this document. A copy of this document has been delivered to the Jersey registrar of companies in accordance with Article 5 of the Companies (General Provisions) (Jersey) Order 2002, and the registrar has given, and has not withdrawn, consent to its circulation. The Jersey Financial Services Commission (the Commission ) has given, and has not withdrawn, its consent under Article 2 of the Control of Borrowing (Jersey) Order 1958 (the Order ), to the issue of the Ordinary Shares and the Special Voting Share by the Company. The Commission has given, and has not withdrawn, its consent under Article 4 of the Order to the issue by the Company of any securities exchangeable into Ordinary Shares of the Company. The Commission has given, and has not withdrawn, its consent to HOC under Article 8 of the Order to the circulation in Jersey of this document. It must be clearly understood that, in giving these consents, neither the Jersey registrar of companies nor the Commission takes any responsibility for the financial soundness of the Company or for the correctness of any statements made, or opinions expressed, with regard to it. The Commission is protected by the Control of Borrowing (Jersey) Law 1947, as amended, against any liability arising from the discharge of its functions under that law. Nothing in this document or anything communicated to the holders or potential holders of Ordinary Shares or Exchangeable Shares by or on behalf of the Company or HOC is intended to constitute, or should be construed as, advice on the merits of the subscription for, Ordinary Shares or Exchangeable Shares or the exercise of any rights attached thereto for the purposes of the Financial Services (Jersey) Law 1998, as amended. JPMorgan Cazenove Limited ( JPMorgan Cazenove ), which is authorised and regulated in the United Kingdom by the Financial Services Authority, has been appointed as Sponsor and is advising the Company and HOC and no one else in connection with the Admission. JPMorgan Cazenove will not be responsible to anyone other than the Company and HOC for providing the protections afforded to its customers or for giving advice in relation to Admission or any transaction or arrangement referred to in this document. The distribution of this document in certain jurisdictions may be restricted by law. No action has been or will be taken to permit the possession or distribution of this document (or any other offering or publicity materials or application form(s) relating to the Ordinary Shares or the Exchangeable Shares) in any jurisdiction, other than the United Kingdom and Jersey, where action for that purpose may be required. Accordingly, neither this document, nor any advertisement or any other offering material may be distributed or published in any jurisdiction except under the circumstances that will result in compliance with any applicable laws and regulations. Persons into whose possession this document comes should inform themselves about and observe any such restrictions. Any failure to comply with these restrictions may constitute a violation of the securities laws of any such jurisdiction. Investors should rely only on the information contained in this document. No person has been authorised to give any information or to make any representations other than those contained in this document and, if given or made, such information or representations must not be relied upon as having been authorised by or on behalf of the Company, HOC or JPMorgan Cazenove. Any delivery of this document shall not, under any circumstances, create any implication that there has been no change in the business or affairs of the Company or of the Group taken as a whole since, or that the information contained herein is correct as of any time subsequent to, the date of this document, save for such statements as are required by law or regulation to refer to one or more future dates. Apart from the liabilities and responsibilities, if any, which may be imposed on JPMorgan Cazenove by the FSMA or the regulatory regime established thereunder, JPMorgan Cazenove accepts no responsibility whatsoever for the contents of this document or for any other statement made or purported to be made by it or on its behalf in connection with the Company, HOC, the Ordinary Shares, the Exchangeable Shares or Admission. JPMorgan Cazenove accordingly disclaims all and any liability whether arising in tort or contract or otherwise (save as referred to above) which it might otherwise have in respect of this document or any such statement. The contents of this document are not to be construed as legal, business or tax advice. Each prospective investor should consult his, her or its own solicitor, financial adviser or tax adviser for legal, financial and/or tax advice in relation to the subscription or purchase of Ordinary Shares or Exchangeable Shares. The distribution of this document in certain jurisdictions may be restricted by law and your attention is drawn to the section headed Important Information on page 32 of this document.

2 CONTENTS SUMMARY INFORMATION... 1 RISK FACTORS DIRECTORS, CORPORATE SECRETARY, SENIOR MANAGERS, REGISTERED OFFICE, DIRECTORS AND SENIOR MANAGERS BUSINESS ADDRESSES, HEAD OFFICE, U.K. OFFICE AND ADVISERS EXPECTED TIMETABLE OF PRINCIPAL EVENTS FORWARD-LOOKING STATEMENTS AND OTHER INFORMATION IMPORTANT INFORMATION PART I INFORMATION ON THE GROUP PART II DIRECTORS, MANAGEMENT AND CORPORATE GOVERNANCE PART III TECHNICAL REPORT PART IV SELECTED FINANCIAL INFORMATION PART V OPERATING AND FINANCIAL REVIEW PART VI CAPITALISATION AND INDEBTEDNESS PART VII FINANCIAL INFORMATION A. FINANCIAL INFORMATION RELATING TO THE COMPANY B. AUDITED (AND UNAUDITED) FINANCIAL INFORMATION RELATING TOHOC C. PRO FORMA FINANCIAL INFORMATION FOR THE COMPANY PART VIII ILLUSTRATIVE PROJECTIONS OF THE GROUP PART IX CORPORATE REORGANISATION PART X ADDITIONAL INFORMATION PART XI DEFINITIONS PART XII GLOSSARY Page i

3 SUMMARY INFORMATION This summary must be read as an introduction to this document. The following summary information has been prepared in accordance with the Prospectus Rules and provides summary information on the Ordinary Shares and the Exchangeable Shares and on the risks of investment therein. Any decision to invest in the Company or HOC should be based upon consideration of this document as a whole by the investor and not just the summary. Following the implementation of the relevant provisions of the Prospectus Directive (Directive 2003/71/EC) in each Member State of the European Economic Area, no civil liability will attach to those persons responsible for this summary in any such Member State, including any translations of this summary, unless it is misleading, inaccurate or inconsistent when read together with the other parts of this document. Where a claim relating to the information contained in this document is brought before a court, in a Member State of the European Economic Area, the plaintiff may, under the national legislation of the Member State where the claim is brought, be required to bear the costs of translating this document before legal proceedings are initiated. 1. INFORMATION ON THE GROUP The Company was incorporated in Jersey on 6 February 2008 to be the ultimate holding company of the Group. The Group was established in 1992 (with HOC being incorporated on 30 October 1996) and commenced trading in the mid-1990s as an independent upstream exploration and production group engaged in the exploration for, and the development, production and acquisition of, oil and gas in its core areas of Africa, the Middle East and Russia. The Group has exploration projects in Uganda, the KRI, the DRC, Malta, Pakistan and Mali, and producing properties in Oman and Russia. HOC, being a member of the Group and in anticipation of Admission, has proposed a reorganisation of its share capital. The reorganisation will culminate in the creation of the Exchangeable Shares which will be subject to voting rights and terms and conditions different from the Ordinary Shares but which, subject to certain conditions, will be exchangeable for Ordinary Shares on a one-to-one basis. HOC intends (at or immediately following Admission) to procure the admission of the Exchangeable Shares to listing on both the TSX and on the Official List together with admission to trading on the London Stock Exchange s main market for listed securities. The Group s management team believes that it has demonstrated a track-record of finding new substantial discoveries, particularly in Africa, including the hydrocarbon system in the Albert Basin, Uganda and the M Boundi oilfield in Congo. The Group s producing, development and exploration projects, together with potential opportunities, provide a combination of early cash flow and longer term value creation opportunities for its shareholders. 2. SUMMARY OF GROUP RESERVES AND RESOURCES RPS has certified that as of 30 September 2007, the Group s net working interest reserves and value, using money of the day prices, discounted at 10 per cent., were as follows: Net Net Working Entitlement Net Interest Reserves Present Reserves Number Value MMboe MMboe $ Millions Proved Probable Additional Total Proved Probable Total Proved Probable Possible RPS has certified that the Group had a 50 per cent. working interest share of the mean risked working interest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at 30 September The Government of Uganda has a back-in right which could, if exercised, reduce the Group s working interest to 42.5 per cent. 1

4 3. GROUP COMPETITIVE STRENGTHS AND COMPETITIVE ADVANTAGES The Directors believe that the Group s competitive strengths are: its ability to secure a portfolio of high-impact international plays; its strong management and technical teams with a track record of finding attractive oil discoveries; its diversified portfolio of assets by geography, product and development stage; the Albert Basin in Uganda which is considered by management to have the potential to contain significant quantities of oil; it has demonstrated its first-mover advantage in acquiring assets in territories such as Uganda and in recent times the KRI; its track record of creating value through asset sales to generate cash to finance development; and its strong financial position as a result of gross proceeds from the completion of a private placement of $165.0 million of convertible bonds in February 2007 and a primary equity fundraising of Cdn$181.5 million completed in November STRATEGY The Group aims to continue to generate further growth in shareholder value through the development, production and acquisition of a portfolio of oil and gas interests. It employs a number of strategic guidelines in its business activities to achieve this, in particular: acquiring and investing in oil and gas properties throughout the world, with a particular emphasis on Africa, the Middle East and Russia; and leveraging off a highly effective network of influential industry, political and institutional relationships, enabling it to gain access to a wide variety of new oil and gas business opportunities to generate future growth for the Group. 5. SUMMARY FINANCIAL INFORMATION The tables below set out the Group s summary financial information for the periods indicated. The data has been extracted without material adjustment from the historical financial information relating to HOC in Part VII of this document. The Group will report under IFRS and so this financial information has been prepared and presented in accordance with IFRS for the nine-month period ended and as at 30 September 2007 (with unaudited comparative financial information for the nine-month period ended and as at 30 September 2006), for the year ended and as at 31 December 2006 and for the year ended and as at 31 December In addition, financial information has been presented in accordance with the previous basis of reporting (Canadian GAAP) for the year ended and as at 31 December 2005 and for the year ended and as at 31 December As this is only a summary, investors are advised to read the whole of this document and not rely on just the key or summarised financial information. Note 28 to the historical financial information in relation to HOC, explanation of transition to IFRS, in Part VII of this document explains the effect of the change of the basis of reporting from Canadian GAAP to IFRS. 2

5 Summary Consolidated Income Statements (for the nine-month period ended 30 September 2007 and financial years 2005 and 2006 prepared in accordance with IFRS and audited and for the nine-month period ended 30 September 2006 prepared in accordance with IFRS and unaudited) Year ended Nine-month periods 31 December ended 30 September $ $ $ $ (Unaudited) Net revenue... 1,184,125 6,834,239 5,475,430 2,843,053 Net expenses... (12,795,257) (19,689,292) (12,646,009) (41,150,721) Gain on disposal of subsidiaries... 1,077,132 Finance income (costs)... (161,534) (27,961,892) (7,764,647) (30,251,946) Income from and gain on disposal of discontinued operations... 3,510,441 12,449,190 2,417,316 Net loss for the period attributable to equity holders of the Corporation... (8,262,225) (28,367,755) (12,517,910) (67,482,482) Net earnings per share from discontinued operations Basic and diluted Net loss per share from continuing operations Basic and diluted... (0.54) (1.86) (0.68) (3.02) Net loss per share Basic and diluted... (0.38) (1.29) (0.57) (3.02) 3

6 Summary Consolidated Balance Sheets (at 30 September 2007 and 31 December 2005 and 2006 prepared in accordance with IFRS and audited and at 30 September 2006 prepared in accordance with IFRS and unaudited) 31 December 30 September $ $ $ $ (Unaudited) Assets Non-current assets Assets held for sale 16,962,091 Intangible exploration assets... 43,503,704 54,767,332 45,602,140 85,746,870 Intangible development costs... 1,187,371 1,574,039 1,346,858 Property, plant and equipment... 25,282,552 32,187,098 25,546,939 59,105,312 Other financial assets ,558 4,200,909 69,973,627 89,443,027 89,458, ,053,091 Current assets Assets held for sale ,412 Inventories ,915 98, ,510 79,768 Prepaid expenses , , , ,402 Trade and other receivables... 1,318,450 9,839, ,953 6,455,303 Cash and cash equivalents... 8,583,321 46,861,146 46,851,571 61,894,711 10,372,908 57,330,846 48,669,345 68,770,184 80,346, ,773, ,127, ,823,275 Liabilities Current liabilities Trade and other payables... 4,438,649 12,715,381 9,396,651 15,781,606 Borrowings , , , ,224 Liabilities of disposal group held for sale ,208 4,686,694 12,863,101 10,344,211 15,941,830 Non-current liabilities Borrowings... 7,520,438 63,124,843 62,512, ,918,765 Derivative financial liability... 27,997,140 8,621,068 32,810,103 Provisions ,849 62, ,274 Liabilities of disposal group held for sale ,770 7,955,287 91,184,305 71,553, ,862,142 12,641, ,047,406 81,897, ,803,972 67,704,554 42,726,467 56,230,090 24,019,303 Shareholders Equity Attributable to Equity Holders of the Corporation Share capital... 22,854,418 24,580,984 23,508,025 40,910,098 Reserves ,956 2,637,058 1,363,795 35,083,262 Retained earnings (deficit)... 43,876,180 15,508,425 31,358,270 (51,974,057) 67,704,554 42,726,467 56,230,090 24,019,303 4

7 Summary Consolidated Cash Flow Statements (for the nine-month period ended 30 September 2007 and financial years 2005 and 2006 prepared in accordance with IFRS and audited and for the ninemonth period ended 30 September 2006 prepared in accordance with IFRS and unaudited) Year ended Nine-month periods 31 December ended 30 September $ $ $ $ (Unaudited) Cash used in operating activities... (7,854,323) (12,737,451) (8,331,393) (7,212,661) Cash used in investing activities... (11,946,720) (28,823,833) (12,074,902) (53,535,576) Cash provided by financing activities... 9,020,147 58,031,186 57,356,469 75,080,072 Cash provided by discontinued operations... 4,313,817 21,324,969 1,009,595 (Decrease) increase in cash and cash equivalents... (6,467,079) 37,794,871 37,959,769 14,331,835 Cash and cash equivalents beginning of period 16,235,523 8,583,321 8,583,321 46,861,146 Foreign exchange (loss) gain on cash held in foreign currency... (1,185,123) 482, , ,730 Cash and cash equivalents end of period... 8,583,321 46,861,146 46,851,571 61,894,711 Summary Consolidated Income Statements (for financial years 2004 and 2005 prepared in accordance with Canadian GAAP and audited) $ $ Net revenue... 6,596,982 8,013,722 Net expenses... (4,501,727) (11,813,535) Gain on sale of property and equipment... 26,269,113 Net earnings (loss)... 28,364,368 (3,799,813) Retained earnings, beginning of year... 24,028,812 52,434,857 Other... 41,677 (740,879) Retained earnings, end of year... 52,434,857 47,894,165 Net earnings (loss) per share: Basic (0.18) Diluted (0.18) 5

8 Summary Consolidated Balance Sheets (at 31 December 2004 and 2005 prepared in accordance with Canadian GAAP and audited) Assets $ $ Current Assets Cash and cash equivalents... 16,235,523 8,583,321 Accounts receivable... 4,640,802 1,318,450 Note receivable... 4,280,161 Inventories... 94, ,474 Prepaid expenses , ,222 25,523,137 10,337,467 Property and equipment... 54,083,097 72,382,935 Deferred development costs... 1,013,012 1,187,371 80,619,246 83,907,773 Liability and Shareholders Equity Current Liabilities Accounts payable and accrued liabilities... 6,397,247 4,438,649 Current portion of long-term debt ,045 6,397,247 4,686,694 Long-term debt... 7,520,438 Asset retirement obligations , ,849 Shareholders Equity: Share capital and warrants... 21,434,168 22,854,418 Contributed surplus... 24, ,209 Retained earnings... 52,434,857 47,894,165 73,893,446 71,265,792 80,619,246 83,907,773 Summary Consolidated Cashflow Statements (for financial years 2005 and 2004 prepared in accordance with Canadian GAAP and audited) $ $ Cash provided by operating activities... 1,866, ,123 Cash used in investing activities... (11,310,312) (16,184,349) Cash provided by financing activities ,953 9,020,147 Foreign exchange gains (losses) on cash held in foreign currency ,001 (1,185,123) Decrease in cash and cash equivalents... (7,933,349) (7,652,202) Cash and cash equivalents, beginning of year... 24,168,872 16,235,523 Cash and cash equivalents, end of year... 16,235,523 8,583, CURRENT TRADING AND PROSPECTS The Company is well positioned to benefit from a series of exploration, appraisal and development drilling programmes in Drilling programmes in Blocks 3A and 1 are scheduled to commence in Uganda in An exploration well is also scheduled to commence drilling in the Miran licence in the KRI in the second half of

9 Production from the Zapadno Chumpasskoye field in Western Siberia should increase from the average of 342 bopd in February 2008 as a result of existing wells being brought on production as well as further development drilling. Production from Block 8, Oman is not expected to change materially from the average net production of 109 bopd of LPG and condensate in January 2008, until the West Bukha field commences production, which is expected to take place in the third quarter of RISK FACTORS Prior to investing in the Ordinary Shares or the Exchangeable Shares, prospective investors should consider the risks associated therewith, including: Risks Relating to the Group s Operations recovery and reserve and resource estimates may prove incorrect; exploration activities are capital intensive and involve a high degree of risk; future appraisal of potential oil and gas properties may involve unprofitable efforts; oil and gas price fluctuations; without the addition of reserves through exploration, acquisition or development activities, the Group s reserves and production will decline over time as reserves are exploited; production operations involve many inherent risks; interruptions in availability of exploration, production or supply infrastructure; third party contractors and providers of capital equipment can be scarce; reliance on other operators and stakeholders limits the Group s control over certain activities; permits, approvals, authorisations, consents and licences may be difficult to obtain, sustain or renew; regulatory requirements can be onerous and expensive; the Group cannot completely protect itself against title disputes; the Group is highly dependent on its executive management; preparation of consolidated IFRS information and dependency on key accounting personnel; environmental liabilities can be significant; additional funding may be required after 12 months from the date of this document; negative operating cash flow could increase the need for additional funding after 12 months from the date of this document; issuance of debt to finance acquisitions would increase the Group s debt levels and there can be no assurance that the Group will be able to meet its obligations in respect of additional debt facilities after 12 months from the date of this document; significant competition attracting and retaining skilled personnel; the international oil and gas industry is highly competitive in all its phases; due diligence of assets and acquisition targets is inherently incomplete; future acquisitions may involve many common acquisition risks; managing the Group s expected growth and development could be challenging; there is a risk of counterparty default or delay; insurance may not be sufficient to cover the full extent of liabilities; currency fluctuations and foreign exchange particularly in relation to United States dollars; labour unrest could affect the Group s ability to explore for, produce and market its oil and gas production; and 7

10 adverse media or other public speculation about the Chief Executive Officer s past associations could materially adversely affect the Group s reputation and the market price of the Ordinary Shares and/or the Exchangeable Shares. Risks Relating to the Countries in which the Group Operates developing countries are subject to greater risk than developed countries; political and social instability may affect the Group, its operations and its personnel; it may be expensive and logistically burdensome to discontinue operations should economic, physical or other conditions subsequently deteriorate; uncertainties of legal systems in jurisdictions in which the Group operates; failure to meet contractual agreements may result in the loss of the Group s interests; and failure to follow corporate and regulatory formalities may call into question the validity of the entity or its assets. Risks Relating to the Group Structure concentration of investments in HOC; lack of operating history; the rights of Shareholders under the laws of Jersey may differ from the rights of shareholders of companies incorporated in other jurisdictions; and there may be difficulty in enforcing against the Group s assets any judgments obtained in Jersey courts. Risks Relating to the Ordinary Shares and the Exchangeable Shares no prior market for the Ordinary Shares and the Exchangeable Shares; market prices of the Ordinary Shares and the Exchangeable Shares may fluctuate significantly; as the Ordinary Shares and the Exchangeable Shares will have separate listings, the trading prices of the Ordinary Shares and the Exchangeable Shares may not reflect equivalent values; the Major Shareholder has the ability to exert significant influence on some of the actions taken by the Shareholders of the Company; there are potential conflicts of interest to which the directors, the senior manager and principal Shareholders of the Company could be subject to in connection with the operations of the Group; sales of the Major Shareholder s Ordinary Shares could decrease the market prices of the Ordinary Shares and the Exchangeable Shares; the Company s shareholding structure may limit claims by Shareholders against subsidiary assets; raising of future equity funds for the Company could result in dilution; payment of dividends is subject to the Company having sufficient distributable reserves; United States and Canadian Shareholders may not be able to participate in any future equity rights offering; and Jersey law limits the circumstances under which shareholders of companies may bring derivative actions. 8. REASONS FOR THE PLAN OF ARRANGEMENT AND LONDON LISTING The Directors believe that the reorganisation of the Group in a tax efficient manner in accordance with the terms of the Arrangement Agreement and the admission of the Ordinary Shares and the Exchangeable Shares to the Official List of the FSA and to trading on the main market of the LSE is in the best interests of the Group and holders of securities in HOC. 8

11 Given the geographic spread of the Group s production, development and exploration licences with a core focus on Africa, the Middle East and Russia, the Directors believe that it would now be more appropriate for the Group to be based in Europe, where a substantial number of holders of securities in HOC and most of the management of the Group reside. The Directors believe that admission to the main market of the LSE will raise the Group s profile and status amongst European investors and within the oil and gas sector generally, and will give the Company access to an international market with a broad, relevant peer group and considerable research expertise. Furthermore, the Directors believe that in due course a listing on the main market in London should assist in increasing the trading and liquidity of the Ordinary Shares and the Exchangeable Shares. The HOC Common Shares will be de-listed from the TSX approximately 2 business days (being business days in London, England or Toronto, Canada) after the effective date of the Plan of Arrangement. However, in order to give Canadian-resident shareholders in HOC a tax efficient method of participating in the Plan of Arrangement such shareholders have been offered Exchangeable Shares as an alternative to exchanging their HOC Common Shares for Ordinary Shares on the effective date of the Plan of Arrangement. The TSX has conditionally approved the listing of the Exchangeable Shares on the TSX subject to the receipt of final documentation. Each HOC Common Share will be exchanged for either ten Ordinary Shares or ten Exchangeable Shares as part of the Plan of Arrangement to help increase the liquidity, following Admission, of the Ordinary Shares and the Exchangeable Shares in addition to providing a suitable initial trading price of shares on the LSE. At a future date after 12 months from the date of this document, in order to finance the remainder of the operation expenditures required to bring the initiated oil and gas exploration activities of the Group into full production the Group is likely to require additional equity and/or debt financing or the sale of noncore assets. For the purposes of the Illustrative Projections of the Group contained in Part VIII of this document, this additional funding is assumed to be equity finance. 9. DIVIDEND POLICY Each of the Company and HOC have not declared or paid any dividends since their inception. For the foreseeable future, the Company anticipates that it will retain future earnings and other cash resources for the operation and development of its business. 10. SIGNIFICANT CHANGE There has been no significant change in the financial or trading position of the Group since 30 September 2007, the date to which the historical financial information in Part VII(B) of this document has been prepared, save for an equity financing, raising gross proceeds of Cdn $181.5 million from the issue of 3 million HOC Common Shares, which closed on 14 November WORKING CAPITAL The Company is of the opinion that the Group has sufficient working capital for its present requirements, that is for at least the next 12 months from the date of this document. 12. THE CITY CODE The City Code will apply to the Company and, on Admission, the shareholders of the Company will be afforded the protections provided by the City Code, in particular the mandatory takeover provisions in rule 9 of the City Code. In the event of a takeover, the squeeze-out provisions in articles 117 to 119 of the Act would be available subject to, amongst other things, the offeror acquiring the requisite percentage of the share capital to which the offer relates. 13. CAPITALISATION AND INDEBTEDNESS The Group s capitalisation as at 31 December 2007 was $260.3 million and its net funds were $38.5 million. 9

12 14. MAJOR SHAREHOLDER On Admission, the Major Shareholder and Mr. Anthony Buckingham, a Director and the Chief Executive Officer of the Company and HOC, will own and control in aggregate 84,540,340 Ordinary Shares representing approximately 33.2 per cent. of the aggregate voting rights in the share capital of the Company. The Major Shareholder and Mr. Anthony Buckingham entered into a relationship agreement with the Company on 28 March The purpose of this agreement is to ensure that transactions and relationships between the Group, the Major Shareholder and Mr. Anthony Buckingham are at arm s length and on normal commercial terms. 15. DIRECTORS AND SENIOR MANAGEMENT On Admission, the members of the Board and their ages and positions will be: Name Age Position Michael Hibberd Chairman and Non-Executive Director Anthony Buckingham Chief Executive Officer Paul Atherton Chief Financial Officer Gregory Turnbull Non-Executive Director John McLeod Non-Executive Director General Sir Michael Wilkes Non-Executive Director On Admission, in addition to the Board, the position of the Senior Manager will be: Name Age Position Brian Smith VP Exploration 16. COMBINED CODE The Directors support high standards of corporate governance. The Company currently complies with all aspects of the Combined Code except for the recommendation that at least half of the board of directors should be determined to be independent and except for the recommendation in the Smith Guidance on the Combined Code that the Chairman of the Company should not be appointed to the Company s Audit Committee. As at Admission, only two of the six directors (excluding the Chairman) are considered by the Board to be independent. However, as soon as is reasonably practicable, the Directors intend to rectify this deficiency in its full compliance with the Combined Code. 10

13 RISK FACTORS Any investment in the Ordinary Shares or Exchangeable Shares is subject to a number of risks. Before making any decision to invest in the Ordinary Shares or Exchangeable Shares, prospective investors should carefully consider all the information contained in this document including, in particular, the specific risks described below. Some of the following factors relate principally to the Group s business and the sector in which it operates. Other factors relate principally to an investment in the Ordinary Shares or Exchangeable Shares. The risks and uncertainties described below are not intended to be exhaustive and are not the only ones facing the Group. Additional risks and uncertainties not currently known to the Directors, or that they currently deem immaterial, may also have an adverse effect on the Group s business, financial condition, results of operations and prospects. If this occurs, the price of the Ordinary Shares and/or Exchangeable Shares may decline and investors could lose all or part of their investment. Investors should consider carefully whether an investment in the Ordinary Shares or Exchangeable Shares is suitable for them in light of the information in this document and their own personal circumstances. Risks Relating to the Group s Operations Recovery and Reserve and Resource Estimates May Prove Incorrect Unless stated otherwise, the reserves and resources data contained in this document are taken from the RPS Report, which has been prepared in accordance with the standards established by the PRMS. The reserves and resources data and the associated estimated future net cash flow from the Group s properties contained in this document have been independently evaluated by RPS and, unless stated otherwise, certified by RPS. There are numerous uncertainties inherent in estimating quantities of reserves and cash flows to be derived therefrom, including many factors that are beyond the control of the Group. Estimating the amount of reserves and resources is a subjective process and, in addition, results of drilling, testing and production subsequent to the date of an estimate may result in revisions to original estimates. The reserves data and cash flow evaluations set forth in this document represent estimates only and should not be construed as representing exact quantities. These estimates and evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and gas, operating costs and royalties and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of the Group. Actual production and cash flows derived therefrom will vary from these estimates and evaluations, and such variations could be material. The foregoing evaluations are based in part on the assumed success of exploitation activities intended to be undertaken in future years. The reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluations. The estimates and evaluations contained in this document may prove incorrect and undue reliance should not be placed on the forward-looking statements contained herein by investors (including in data contained within the RPS Report or extracted or derived from the RPS Report and whether expressed to be certified by RPS or otherwise) concerning the Group s reserves and resources or production levels. Whilst reserves are stated in accordance with the PRMS reserve and resource definitions, certain categories of reserves and resources (such as prospective or contingent resources) are inherently less certain than other categories (such as 1P or proved reserves). If the assumptions upon which the estimates of the Group s reserves or resources have been based prove to be incorrect, the Group may be unable to recover and produce the estimated levels or quality of oil or gas and the Group s business, prospects, financial condition or results of operations could be materially and adversely affected. Exploration Activities are Capital Intensive and Involve a High Degree of Risk Oil and gas exploration activities are capital intensive and involve a high degree of risk. There is no assurance that expenditures made on future exploration by the Group will result in new discoveries of oil or gas in commercial quantities. It is difficult to estimate the costs of implementing any exploratory drilling programme due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over-pressured zones, tools lost in the hole and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. If exploration activities prove unsuccessful over a prolonged period of time, the 11

14 Group may not, after twelve months from the date of this document, have sufficient working capital to continue to meet its obligations and its ability to obtain additional financing necessary to continue operations may also be adversely affected. Future Appraisal of Potential Oil and Gas Properties May Involve Unprofitable Efforts The Group s future appraisals of potential oil and gas properties may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs and expenses. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs and expenses. In addition, drilling hazards or environmental damage could greatly increase the cost of operations. Various field operating conditions may also adversely affect the production from successful wells including delays in obtaining governmental approvals, permits, licences, authorisations or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximising production rates over time, production delays and declines from normal field operating conditions cannot be eliminated. Any such productions, delays and declines could be expected to adversely affect revenue and cash flow levels. Whether the Group ultimately undertakes an exploration or development project depends upon a number of factors, including availability of and cost of capital, current and projected oil and gas prices, receipt of government approvals, access to the relevant property, the costs and availability of drilling rigs and other equipment, supplies and personnel necessary to conduct operations at the property, success or failure of similar activities in similar areas and changes in the expected levels of capital expenditure to complete the project. The Group continues to gather data about its new venture opportunities and new projects on an ongoing basis. Additional information may cause the Group at any time to alter its project schedule or determine that a new venture opportunity or project should not be pursued, which could adversely affect the Group s business and prospects. Under certain of the Group s PSCs and concession agreements, the Group is obliged to finance exploration, development and operations of the relevant property, and the related facilities and equipment and will only recover its costs if there is successful production in accordance with the terms of the PSCs and agreements. However, there can be no assurance that the Group will discover commercial quantities of oil or gas at such operations. Accordingly, there can be no assurance that the Group will recover its initial outlay of capital expenditure and operating costs at any such operation, and in such event the Group s business, financial condition, results of operations and prospects could be materially and adversely affected. Oil and Gas Prices Fluctuate The Group s results of operations and financial condition are significantly affected by prevailing prices of oil and gas. Historically, prices of oil and gas have been subject to wide fluctuations for many reasons, including: global and regional supply and demand, and expectations regarding future supply and demand, for oil and gas; global and regional economic conditions; political, economic and military developments in oil and gas producing regions; prevailing weather conditions; prices and availability of alternative sources of energy; geopolitical uncertainty; the ability of members of OPEC, and other oil producing nations, to set and maintain specified levels of production and prices; and governmental regulations and actions, including the imposition of export restrictions and taxes. It is impossible to accurately predict future oil and gas price movements. The Company can give no assurance that existing prices for oil and gas will be maintained in the future. Any material decline in such prices could result in a reduction of the Group s net production revenue and a decrease in the valuation of the Group s exploration, appraisal and development properties. The economics of producing from some 12

15 wells may change as a result of lower prices, which could result in a reduction in the volumes produced by the Group. The Group might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Group s net production revenue and the financial resources available to it to make planned capital expenditure. This would have a material adverse effect on the Group s financial condition, business, prospects and results of operations. From time to time, the Group may enter into agreements to receive fixed prices on its oil and gas production to offset the risk of revenue losses if commodity prices decline, which is known as hedging; however, if commodity prices increase beyond the levels set in such agreements, the Group will not benefit from such increases and the Group may nevertheless be obligated to pay royalties on such higher prices, even though they were not received by it, after giving effect to such agreements. Whilst the Group has not currently entered into any hedging instruments at the present time, if it were to do so in the future it could also be subject to margin requirements associated with these instruments. Because the Group is not currently hedging it is currently exposed to fluctuations in oil and gas prices which could materially affect the Group s financial condition, business, prospects and results of operations. Without the Addition of Reserves through Exploration, Acquisition or Development Activities, the Group s Reserves and Production will Decline Over Time as Reserves are Exploited The Group s future oil and gas reserves, production and cash flows to be derived therefrom are highly dependent on the Group s success in exploiting its current reserve base and acquiring or discovering additional reserves. Without the addition of reserves through exploration, acquisition or development activities, the Group s reserves and production will decline over time as reserves are exploited. A future increase in the Group s reserves will depend not only on the Group s ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Group s future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and gas. If such efforts are unsuccessful, the Group s total reserves may not increase or may decline, which could have a material adverse effect on the Group s business, financial condition, prospects and results of operations. Production Operations Involve Many Inherent Risks Production operations of the Group or by operators of assets in which the Group has an interest involve risks normally inherent in such activities such as premature declines of reservoirs, blow-outs, oil spills, explosions, fires, equipment damage or failure, natural disasters, geological uncertainties, unusual or unexpected rock formations, abnormal pressures, cratering and sulphur gas releases. Offshore operations of the Group may also be subject to natural disasters as well as to hazards inherent in marine operations and damage to pipelines and subsea facilities from trawlers, anchors and vessels. The occurrence of any of these events could result in environmental damage, injury to persons and loss of life, a failure to produce oil or gas in commercial quantities or an inability to fully produce discovered reserves. Consequent production delays and declines from normal field operating conditions can be expected to adversely affect revenue and cash flow levels to varying degrees. Oil and gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations. The Group s production is currently sourced from its interests in a limited number of PSCs or concessions agreements. Should the Group encounter any problems in any one PSC or concession, it could have a material adverse impact upon the Group s planned levels of production. Interruptions in Availability of Exploration, Production or Supply Infrastructure Oil and gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Current high demand for such limited equipment or access restrictions is affecting the availability and cost of such equipment to the Group and operators or production facilities in which the Group has an interest and from time to time delays exploration and development activities. Such interruptions or delays in the availability of infrastructure, including drilling rigs in particular and pipelines and storage tanks, on which exploration and production activities are dependent could result in disruptions to the Group s projects, increased costs, and may have an adverse effect on the Group s profitability. 13

16 Third Party Contractors and Providers of Capital Equipment Can Be Scarce The Group contracts or leases services and capital equipment from third party providers. Such equipment and services can be scarce and may not be readily available at times and places required. In addition, costs of third party services and equipment have increased significantly over recent years and may continue to rise. Scarcity of equipment and services and increased prices may in particular result from any significant increase in exploration and development activities on a region by region basis which might be driven by high demand for oil and gas. In the regions in which the Group operates there is significant demand for capital equipment and services. The unavailability and high costs of such services and equipment could result in a delay or restriction in the Group s projects and adversely affect the feasibility and profitability of such projects and therefore have an adverse affect on the Group s business, financial condition, results of operations and prospects. Reliance on other Operators and Stakeholders Limits the Group s Control Over Certain Activities To the extent the Group is not the operator of its oil and gas properties, including in Oman where RAK Petroleum is the operator and in the DRC where Tullow is the operator, it will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators or the costs of production and exploration of such operations. In addition, the success of the 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 Group s non-operated exploration, development and production activities, which could materially and adversely affect the Group s business, financial condition, results of operations and prospects. The terms of any relevant operating agreement generally impose standards and requirements in relation to the operator s activities. While the Group has deliberately acquired interests in oil and gas properties that are operated by operators it believes to be reputable, 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 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 Group alone or in conjunction with other participants at the desired time or at all. Other participants who have invested in the 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 Group may be required under the terms of the relevant operating agreement to contribute all or part of any such funding shortfall. After the twelve month period from the date of this document, any such delay or inability to undertake such activities, increased cost or obligation to provide further funding could adversely affect the Group s business, financial condition, results of operations and prospects. Permits, Approvals, Authorisations, Consents and Licences May Be Difficult to Obtain, Sustain or Renew The operations of the Group require licences, approvals, authorisations, consents and permits and in some cases renewals of existing licences, approvals, authorisations, consents and permits from various governmental authorities. The Directors believe that the Group currently holds or has applied for all necessary licences, approvals, authorisations, consents and permits to carry on the activities which it is currently conducting under applicable laws and regulations in respect of its properties, and also believe that the Group is complying in all material respects with the terms of such licences, approvals, authorisations, consents and permits or extensions thereof. However, the Group s ability to obtain, sustain or renew such licences, approvals, authorisations, consents and permits on acceptable terms are subject to changes in regulations and policies and to an extent, on the discretion of the relevant governments. To the extent any such approvals, permits, authorisations, licences and consents are required and not obtained or maintained, the Group may be curtailed or prohibited from proceeding with planned exploration or development of oil and gas properties. Amendments to current laws, regulations and permits, authorisations, licences, consents and approvals governing operations and activities of oil and gas companies, or more stringent implementation thereof, could result in increases in capital expenditure or production costs or a reduction in levels of production from producing properties or require abandonment or delays in development of new properties, all of 14

17 which could have a materially adverse effect on the Group s business, financial condition, prospects and results of operations. Regulatory Requirements can be Onerous and Expensive The current or future operations of the Group, including development activities and commencement of production on its properties, require permits, authorisations, licences, consents and approvals from various foreign, federal, state and local governmental authorities and such operations are and will be governed by applicable laws and regulations governing oil and gas exploration and development, exports, taxes, labour standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Any changes or requirements additional to any such applicable laws, regulations and permitting requirements may require the installation of additional equipment or remedial actions in order to ensure compliance with such amendments, which may be expensive. Failure to comply with applicable laws, regulations and permitting requirements may result in enforcement actions in local jurisdictions thereunder, including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment or remedial actions. Parties engaged in oil and gas operations may be required to compensate those suffering loss or damage by reason of such activities and may have civil or criminal fines or penalties imposed for violations of applicable laws or regulations. The Group Cannot Completely Protect Itself Against Title Disputes In many of the countries in which the Group operates, land title systems are not developed to the extent found in many industrialised countries and there may be no concept of registered title. Although the Group believes that it has good title to its oil and gas properties, it cannot control or completely protect itself against the risk of title disputes or challenges. There can be no assurance that claims or challenges by third parties against the Group s properties will not be asserted at a future date. The Group received a letter from the Iraq Ministry of Oil, dated 17 December 2007, stating that the PSC signed with the KRG (without the prior approval of the Iraqi government) is considered to be void by the Iraqi government as they have stated it violates the prevailing Iraqi law. On the basis of KRI legal advice, the Directors believe that the PSC is valid and effective pursuant to the applicable laws. The Group also received a letter from the chairman of the Management Committee of the National Oil Corporation of Libya, dated 28 February 2008, stating that the Block 7 licence area offshore Malta lies within the Libyan continental shelf and a portion of this area has already been licensed to Sirte Oil Company. This letter also demands that the Group refrain from any activities over or concerning the Block 7 licence area and asserts the Libyan government s right to seek to invoke Libyan and international law to protect its rights in the Block 7 licence area. The Directors believe that the Libyan government s claims are unfounded. In addition, the DRC work programme pursuant to the DRC PSC cannot be commenced prior to the grant of a presidential decree from the DRC government. The validity of the award of the DRC licences to which the work programme relates is currently being disputed by the Congolese Oil Ministry; this is being rigorously defended by the Group and its partner. There can be no assurance that final approval or ratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscal terms will not be re-negotiated at a later date by the DRC government. The Group holds rights to explore its various oil and gas properties, but no assurance can be given that relevant governments will not revoke, or significantly alter the conditions of, the applicable exploration and development authorisations, licences, permits, approvals and consents and that such exploration and development authorisations, licences, permits, approvals and consents will not be challenged or impugned by third parties. There is no certainty that existing rights or additional rights applied for will be granted or renewed on terms satisfactory to the Group. The Group is Highly Dependent on its Executive Management The Group is highly dependent upon its executive management and the loss of such executive management could have a materially adverse effect on the Group. In particular, the Chief Executive Officer of the Company and HOC, Mr. Anthony Buckingham, has a number of key relationships that are important to 15

18 the Group s business and existing oil and gas properties. The Group does not have any key-man insurance policies, and therefore there is a risk that the unexpected loss of services of any member of executive management (through serious injury, death or resignation) could have a materially adverse effect on the Group. In addition, in assessing any risk associated with an investment in the Ordinary Shares or Exchangeable Shares, it should be recognised that any investor would be relying on the ability and integrity of the existing management of the Company. The Group s preparation of its consolidated IFRS financial information can be a technical task and is dependent on key accounting personnel The preparation of the Group s consolidated IFRS financial information is a fairly complex task requiring IFRS-experienced accounting personnel and involving the recording of complicated and non-routine transactions that are technical in nature. There is an increasing demand for a limited number of IFRS-experienced accounting personnel who also have knowledge of Canadian GAAP as more Canadian companies prepare financial statements on the basis of IFRS or other international standards. Furthermore, HOC, as a listed entity in Canada, has historically prepared its consolidated financial information according to Canadian GAAP and applied Canadian corporate practice and financial reporting procedures to the Group such that there can be no guarantee that the Group will not face difficulties in preparing consolidated IFRS financial information or applying its new U.K. financial reporting procedures in all circumstances in the future. Any of the above factors could materially adversely affect the Group s business, results of operations, financial condition and prospects. However, in any event, the Group does consult with third-party experts from time to time in relation to technical matters in relation to recording items in its financial statements and the nature of its financial reporting procedures and notwithstanding the above, the Directors believe that the Group s financial systems, which have been reviewed by its professional advisers, are sufficient to ensure compliance with the requirements of the DTR as a listed entity. Environmental Liabilities Can Be Significant Significant liability could be imposed on the Group for damages, clean-up costs or penalties in the event of certain discharges into the environment, environmental damage caused by previous owners of property purchased by the Group, acts of sabotage or non-compliance with environmental laws or regulations by the Group. Such liabilities could have a materially adverse effect on the Group. It is not possible to predict what future environmental regulations will be enacted or how current or future environmental regulations will be applied or enforced in the future. The Group may have to incur significant expenditure for the installation and operation of systems and equipment for remedial measures in the event that environmental regulations become more stringent or governmental authorities choose to enforce them more vigorously. Any such expenditures may have a materially adverse effect on the Group s business, financial condition and results of operations. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the cost of production, development or exploration activities or otherwise adversely affect the Group s business, financial condition, results of operations or prospects. As a party to various PSCs and concession agreements, members of the Group may have undertaken obligations to restore production areas to standards acceptable to the relevant state authorities at the end of the production fields commercial lives. Parties to such PSCs are typically liable for their share of any decommissioning work. Any obligation to decommission a production facility may involve a substantial expenditure. These decommissioning costs are necessarily incurred at a time when the related production facilities are no longer generating revenue and no provisioning has been made in the Group s accounts for such future decommissioning costs. It is intended that the decommissioning costs, when they arise, will be borne by the Group out of production revenue. There can, however, be no assurance that the production revenue will be sufficient to meet these decommissioning costs as and when they arise, and if the Group has to apply other or additional financial resources to meet these costs instead, it could have a materially adverse effect on the Group s business, financial condition, results of operations or prospects. Additional Funding May be Required After Twelve Months From the Date of this Document At a date some time after twelve months from the date of this document, depending on future exploration, development, production or acquisition plans, the Group may require additional financing. There is no assurance that the Group will be successful in obtaining required financing on acceptable terms at the relevant time or at all. The location of the Group s oil and gas properties in developing countries may make it more difficult to obtain such financing. 16

19 Failure to obtain additional financing on a timely basis could cause the Group to forfeit its interest in such properties, reduce or terminate its operations or curtail its operations, exploration or development plans. If, after twelve months from the date of this document, the Group s cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements and this will have a materially adverse effect on the Group s business, prospects, liquidity, financial condition, cash flows and results of operations. Negative Operating Cash Flow Could Increase the Need For Additional Funding After Twelve Months From the Date of this Document Although the Group has sufficient working capital to meet its present requirements, being for the period which is twelve months after the date of publication of this document, the Group s ability thereafter to generate sufficient operating cash flow to make scheduled payments on its indebtedness and meet other capital requirements will depend on its future operating and financial performance. The Group s future performance will be impacted by a range of economic, competitive and business factors that it cannot control, such as general economic and financial conditions in its industry, including fluctuations in prevailing oil and gas prices, or the economy generally. A significant reduction in operating cash flows resulting from changes in economic conditions, increased competition, or other challenges identified as risk factors in this document could increase the need for additional financings or alternative sources of liquidity and could have a material adverse effect on the Group s business, financial condition, results of operations, prospects and its ability to service its debt and other obligations. If the Group is unable to service its indebtedness in the future, it will be forced to adopt an alternative strategy that may include actions such as selling assets, restructuring or refinancing its indebtedness, seeking additional equity capital or reducing capital expenditures. Furthermore, the Group may not be able to effect any of these alternative strategies on satisfactory terms, if at all, or they may not yield sufficient funds to make required payments on its indebtedness. Issuance of Debt to Finance Acquisitions Would Increase the Group s Debt Levels From time to time, the Group may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase the Group s debt levels above industry standards. After twelve months from the date of this document, there can be no assurance that the Group will at any time be able to meet its obligations in respect of such additional debt facilities and any actions taken by counterparties in relation to default may have a material adverse effect on the Group s business, prospects, liquidity, financial condition, cash flows and results of operations. After twelve months from the date of this document, the level of the Group s indebtedness from time to time could impair its ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise and limit the Group s operational flexibility. Significant Competition Attracting and Retaining Skilled Personnel Attracting and retaining additional skilled personnel will be required to ensure expansion of the Group s business. The Group faces significant competition for skilled personnel in the oil and gas sector. Skilled personnel are required in the areas of exploration and development, operations, engineering, business development, oil and gas marketing, finance and accounting. There is no assurance that the Group will successfully attract new personnel or retain existing personnel required to continue to expand its business and to successfully execute and implement its business strategy. The International Oil and Gas Industry is Highly Competitive in all its Phases The international oil and gas industry is highly competitive in all its phases. Competition is particularly intense in the acquisition of prospective oil and gas properties, exploration and production licences, and oil and gas reserves. The Group s competitive position depends on its geological, geophysical and engineering expertise, its financial resources, and its ability to develop its properties on time and on budget and its ability to select, acquire and develop proved reserves and on its ability to foster and maintain relationships with governments of the countries in which it operates. The Group competes with numerous other participants in the search for oil and gas, the acquisition of oil and gas properties on time and on budget and in the marketing of oil and gas. The Group s competitors include oil and gas companies which have greater financial resources, more local contacts, staff and facilities than the Group. Many such competitors not only explore for and produce hydrocarbons, but also carry on refining and marketing of oil and gas and 17

20 other products on a world-wide basis. Additionally, companies not previously investing in oil and gas or operating in that sector may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies will also provide competition for the Group. The Group s ability to increase reserves in the future will depend not only on its ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and gas include price and methods and reliability of delivery. The Group competes with major and independent oil and gas companies and other industries supplying energy and fuel in the marketing and sale of oil and gas to transporters, distributors and end-users, including industrial, commercial and individual consumers. Due Diligence of Assets and Acquisition Targets is Inherently Incomplete The Group s strategy includes increasing its oil and gas reserves through acquisitions of interests in further oil and gas properties. Although the Group performs a review of the companies, businesses and properties it acquires (or intends to acquire) to standards consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. The Group will commonly focus its due diligence efforts on higher value properties and will simply review the lower value interests on a sample basis. However, even in-depth due diligence reviews may not reveal existing or potential problems, nor will they permit the acquirer to become sufficiently familiar with the properties to fully assess their potential or limitations and deficiencies. A physical inspection may not be performed on every well, and structural or environmental problems, such as ground water contamination, are not always observable or evident when a due diligence review is carried out. On that basis, the Group may, in making any acquisition, assume liabilities in relation to the relevant asset, including environmental liabilities. There can be no assurance that any acquisition by the Group will be successful in whole or in part. Future Acquisitions May Involve Many Common Acquisition Risks Risks commonly associated with acquisitions of companies, businesses or properties include the difficulty of integrating operations and personnel in relation to any such business or property, problems with minority shareholders if the transactions are structured as the acquisition of companies, the potential disruption of the Group s own business, the diversion of management s time and resources from the existing Group business, and the possibility that indemnification agreements with sellers may be unenforceable or insufficient to cover potential liabilities and difficulties arising out of integration. Furthermore, the value of any business, company or property that the Group acquires or invests in may actually be less than the amount it pays for it or its estimated production capacity or potential may be lower than expected. Managing the Group s Expected Growth and Development Could Be Challenging The Group has experienced significant growth and development over a short period of time and expects to continue to grow through further exploration success and production increases from its oil reserves. Management of the expected growth requires, among other things, stringent control of financial systems, operations and processes, the continued development of management controls, the training and hiring of new personnel and continued access to funds to finance this growth. Failure to successfully manage the Group s expected growth and development could have a material adverse effect on the Group s business, financial condition, results of operations and prospects. There is a Risk of Counterparty Default or Delay The Group has entered into agreements with a number of contractual counterparties in relation to the sale and supply of its oil and gas production volumes. Accordingly, the Group is subject to the risk of counterparty default or delayed or withheld payments. In certain areas in which the Group operates, its selection of counterparties may be constrained either legally or as a result of geographic, infrastructure or other constraints or factors. All of the Group s production in the last five years has been derived from the Congo, Oman and Russia. In 2006 and 2007, the Group sold all of its production, in each country, to a single customer for each commodity. Substantially all of the Group s accounts receivables from oil and gas sales were from three credit-worthy customers and debtors of the Group are subject to internal credit review to minimise the risk of non-payment. However, there can be no assurance that such customers and debtors will not default and the absence of competitors for the transmission or purchase of oil and gas produced by the Group may expose it to disadvantageous 18

21 contractual or pricing terms, both of which could adversely affect the Group s business, results of operations, financial condition and prospects. Insurance May Not be Sufficient to Cover Full Extent of Liabilities The Group s involvement in the exploration for and development of oil and gas properties may result in the Group becoming subject to liability for claims for matters including pollution, blow-outs, environmental damage, cratering and fires all of which may result in property damage, personal injury or other hazards or for the acts or omissions of sub-contractors, operators and joint venture partners. Although, the Group may have received indemnities from such sub-contractors, operators and joint venture partners, such indemnities may be difficult to enforce given the financial positions of those giving the indemnities or due to the jurisdiction in which the Group seeks to enforce the indemnities. The Group believes that the level of insurance cover it maintains is adequate based on various factors such as the cost of the policies, industry standard practice and the risks associated with the exploration and development of oil and gas properties in the countries in which it operates. The Group does not maintain key-man insurance. Although the Group has obtained insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances the Group may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to the Group. The occurrence of a significant event that the Group is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Group s financial position, business, results of operations or prospects. Currency Fluctuations and Foreign Exchange Particularly in Relation to United States Dollars The Group s current capital expenditures, exploration commitments, revenues and cost base are denominated primarily in United States dollars and, to a lesser extent, in currencies of other countries, such as Russian roubles. Where there are fluctuations in the United States dollar exchange rate, the Group s revenue margins and capital expenditures may be materially affected. Expenses in Russian roubles are partially offset by income earned in Russian roubles. The developing countries in which the Group operates or proposes to operate impose or may impose foreign exchange restrictions that may materially affect the Group s financial condition, business, prospects and results of operations. Labour Unrest Could Affect the Group s Ability to Explore For, Produce and Market its Oil and Gas Production The Group may be required to hire and train local workers in its oil and gas operations. Some of these workers may be organised into labour unions. Any strike activity or labour unrest in any such local jurisdiction or at any oil and gas operation could adversely affect the Group s ongoing operations and its ability to explore for, produce and market its oil and gas production. Adverse media or other public speculation about the Chief Executive Officer s past associations could materially adversely affect the Group s reputation and the market price of the Ordinary Shares and/or the Exchangeable Shares As disclosed in Section 9 History and Development of Part I of this document, prior to 1998, the Chief Executive Officer of the Company had associations with certain companies, namely Executive Outcomes and Sandline International, which were principally engaged as private military contractors in Angola, Sierra Leone and Papua New Guinea. Since the cessation of operations of those companies in 1998, the Chief Executive Officer has had no association with any private military contractors or similar companies or activities and the Group has no assets or current intentions to operate in the countries in which Executive Outcomes and Sandline International operated. Further, there is no connection between the assets of the Company and the previous involvement of the Chief Executive Officer with private military contractors and, as far as the Company is aware, no formal allegation in this regard has ever been made. However, as a result of these historic associations, there has been, from time to time and may periodically be in the future, media and other public speculation about the Chief Executive Officer s associations with private military contractors and/or individuals involved with those types of companies. Any adverse media speculation or other public statements about the Chief Executive Officer could materially adversely affect the Group s reputation and the market price of the Ordinary Shares. 19

22 Risks Relating to the Countries in which the Group Operates Developing Countries are Subject to Greater Risk than Developed Countries Certain of the Group s significant oil and gas interests are located in developing countries some of which have historically experienced periods of civil unrest, terrorism, violence and war, as well as political and economic instability. Future oil and gas exploration and development activities in such developing countries may be affected in varying degrees by government regulations, policies or directives with respect to restrictions on production or sales, price controls, export controls, repatriation of income, changes in income taxes and other local tax laws, carried interests for the state, expropriation of property and environmental legislation. There are inherent risks of uncertainty in, and changes to, laws such as tax laws in such developing countries. The Group will also be required to negotiate property development agreements with the governments having jurisdiction over some of its properties. Such governments may impose conditions that could affect the viability of any given project such as providing the government with free carried interests, requiring local company participation, or providing subsidies for the development of the local infrastructure or other social assistance. There can be no assurance that the Group will be successful in concluding such agreements with any relevant governmental entity on commercially acceptable terms or that these agreements will be successfully enforced in the foreign jurisdictions in which the Group s properties are located. Operations may also be affected in varying degrees by political and economic instability such as frequent changes to tax laws or fiscal policy, economic or other sanctions imposed by the other countries, including expropriation of assets, terrorism, civil wars, guerrilla activities, military repression, crime, material fluctuations in currency exchange rates and high inflation. The political status of certain countries in which the Group operates may make it more difficult, in particular after twelve months from the date of this document, for the Group to obtain any required project financing from senior lending institutions because such lending institutions may not be willing to finance projects in these countries due to the perception of investment risk. Infrastructure development in many of the countries in which the Group operates is limited. In addition, a significant portion of the Group s properties are located in remote areas, many of which are difficult to access, and some countries in which the Group operates such as Uganda, are landlocked and have poor infrastructure. The Group has recently encountered supply and transport difficulties into and out of Uganda due to the political and civil unrest in neighbouring Kenya, and the main trade route to Mombasa on the Kenyan coast has intermittently been closed off since troubles in Kenya escalated, although the situation has improved in March These factors may affect the Group s ability to explore and develop its properties and to store and transport its oil and gas production. There can be no assurance that future instability in one or more of the countries in which the Group operates (or in the neighbouring countries), actions by companies doing business there, or actions taken by the international community will not have a material adverse effect on the countries in question and in turn on the Group s financial condition, business, prospects, liquidity or results of operations. Political and Social Instability May Affect the Group, its Operations and Its Personnel Certain countries where the Group has interests have a publicised history of political and social instability which culminate in security problems and which may affect the Group, its operations and its personnel. It may be difficult or impossible to obtain insurance coverage to protect against civil strife, labour unrest, outbreaks of infectious disease, armed conflict, acts of war, terrorism and other security incidents and as a result, the Group s insurance programme may exclude this coverage. Consequently, such risks could have a materially adverse impact on the Group s reputation, operations and prospects. The Group s operations may also be affected in varying degrees by political and economic instability, economic or other sanctions imposed by other countries, terrorism, civil wars, border disputes, guerrilla activities, military repression, civil disorder, crime, stability of the workforce, extreme fluctuations in currency exchange rates and high inflation. Any changes in regulations or shifts in economic (including tax or fiscal policy) or political conditions are beyond the control of, and may adversely affect, the Group s business, financial condition, results of operations and prospects. Russia Despite Russia s broad shift to a market-oriented economy and democratic institutions, the Russian political system remains vulnerable to the consequences of large-scale privatisations in the 1990s and demands for autonomy from certain regional and ethnic groups. Since President Putin was elected in March 2000, Russia has generally experienced a significantly higher degree of governmental stability, with the government establishing control over the private interest groups that flourished during the Yeltsin 20

23 years. In addition, since December 2003 the lower houses of Russia s parliament have been dominated by political parties in support of former President Putin, which has translated into a period of stability and prosperity for Russia at large. Possible future changes in the government, major policy shifts or any possible lack of consensus between the president, the government, Russia s parliament and powerful economic lobby groups could lead to political instability, which could have a material adverse effect on the Group s operations in Russia. In Russia, the division of authority between federal and regional authorities in respect of the development and implementation of state policy, in relation to the exploration, production, transport and sale of oil and gas and the industrial and environmental safety concerns may lead to a climate of uncertainty in the Group s Russian operations. Such uncertainty could hinder the Group s long-term planning efforts in Russia, and may create uncertainties in its operating environment. These uncertainties may also prevent the Group from effectively and efficiently carrying out its business strategy in respect of its Russian operations. KRI In October 2007, the Group, through a wholly-owned subsidiary, entered into a PSC with the government of the KRI to explore for oil and gas in the KRI. The KRI is located in northern Iraq. Iraq is currently experiencing periods of civil unrest and political and economic instability. In addition, the Government of Turkey recently authorised Turkey s military to make incursions into Iraq in order to carry out cross-border assaults against the Kurdistan Workers Party. The Turkish military has recently amassed a significant number of troops along the Iraqi border, and has carried out air strikes and conducted limited shelling of targets in northern Iraq. Additionally, the national government of Iraq has been considering and may bring into force a new petroleum law, and the PSC with the KRI may, accordingly, be subject to challenge or changes once such a federal law comes into effect. As at the date of this document, the new Iraqi petroleum law has yet to be brought into force and it is not clear how the Iraqi government and U.S. State Department sentiment will affect the Group s interests in the KRI. Furthermore, the Group received a letter from the Iraq Ministry of Oil dated 17 December 2007, stating that contracts signed with the KRG without the prior approval of the government of Iraq are to be considered annulled as they violate the prevailing Iraqi law. There can, therefore, be no assurance that the PSC in the KRI will not be adversely affected by the actions of the Iraqi government authorities or others and the validity and effectiveness of and enforcement of such PSC in Iraq cannot be assured. This could have a materially adverse effect on the Group s ability to obtain oil and gas licences in other areas of Iraq. No assurances can be given that the Group will be able to maintain or obtain effective security or insurance of any of its assets or personnel in Iraq where, at times, terrorism and insurgent activities have disrupted various business activities during the past and may affect the Group s operations or plans in the future. Currently military forces from the United States of America and other allied countries are operating within Iraq to assist the new local government to maintain peace and national security and law and order at the national level. There can be no assurances that the commitment of these foreign nations to maintain their military presence will continue in the short to medium term nor can there be assurances that the local government of Iraq can itself provide the necessary degree of peace, order, stability and security without foreign military assistance. As such, the Group s ability to maintain effective security over its assets may be adversely impacted in the KRI. Uganda The Group holds rights to explore and develop oil and gas properties in and around Lake Albert, which straddles the border of Uganda and the DRC. There is a long history of war and other forms of hostility between Uganda and the DRC, and both countries have experienced civil conflict, terrorism and guerrilla activities for a number of decades, although great efforts have been made to bring stability to Uganda. There can be no assurance that the conflict between Uganda and the DRC or that internal conflict in these countries will not continue. DRC The DRC has a history of prolonged periods of war and pronounced political and civil unrest. Whilst considerable efforts have been made to bring stability to the country, there remains some unrest in the DRC, although this is mostly in the north-eastern region. As a result, the Group s operations may be exposed to various levels of political risk and regulatory uncertainties, including government regulations, 21

24 policies or directives in relation to foreign investors, restrictions on production, price controls, export controls, income taxes, nationalisation or expropriation of property, repatriation of income, royalties and environmental legislation. The DRC PSC has not yet been ratified by the DRC government authorities and may, therefore, be subject to further detailed negotiation. Furthermore, the work programme pursuant to the DRC PSC cannot commence prior to the grant of a presidential decree from the DRC government. There can be no assurance that ratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscal terms will not be re-negotiated at a later date by the DRC government. The DRC licences are currently being disputed by the Congolese Oil Ministry; this is being rigorously defended by the Group and its partner. Accordingly, it is possible that if such PSC is not ratified in its current form, this could have a material adverse effect on the Group s business, results of operations, financial condition and prospects. Pakistan The Group holds rights to explore and develop an oil and gas property in the province of Baluchistan of Pakistan. The province has experienced civil conflict, terrorism and guerrilla activities for a number of decades. It May be Expensive and Logistically Burdensome to Discontinue Operations Should Economic, Physical or Other Conditions Subsequently Deteriorate Once the Group has an interest in an established oil and gas exploration and/or production operation in a particular country, it may be expensive and logistically burdensome to discontinue such operation should economic, physical or other conditions subsequently deteriorate. Such deterioration in any of the countries in which the Group operates could be caused by some of the factors described below, and could have a material adverse effect on the Group s ability to continue to exploit its established oil and gas exploration and/or production prospects in these countries. Russia Russia experienced a significant economic crisis in the late 1990s which was instigated by the Russian government s default on its rouble-denominated fixed income securities and a temporary moratorium was imposed on certain hard currency payments. These actions culminated in a severe devaluation of the rouble and a sharp increase in the rate of inflation. Since this crisis, the Russian economy has experienced positive trends, such as an increase in gross domestic product, a relatively stable rouble, a reduced rate of inflation and rising prices in world markets for the crude oil and gas that Russia exports. No assurance can be given that such positive trends will continue and a decline in the prices of crude oil and gas could have an adverse effect on Russia s economy. Certain of the Group s capital costs relating to equipment hires and purchases and employee salaries in respect of its operations in Russia may be materially affected by increased inflation rates in Russia which in turn could affect the Group s operating profits, financial condition and results of operations. KRI As a direct result of the actions of the Kurdistan Workers Party, de facto economic sanctions have been imposed on the KRI by Turkey and they have threatened to close the one border crossing for heavy lorries, through which vital supplies of food and equipment reach the KRI. In the wake of the recent war in Iraq, the KRI has remained relatively stable and free of the civil unrest and terrorism that has plagued the southern regions of the country. The stability of the KRI (compared to other regions of Iraq) has allowed it to achieve a higher level of development than other regions in Iraq. In 2004 the per capita income in the KRI was 25 per cent. higher than in the rest of Iraq. Following the removal of Saddam Hussein s administration and the subsequent violence, the three provinces fully under the KRG s control were the only three in Iraq to be ranked secure by the U.S. military. The relative security and stability of the region has allowed the KRG to sign a number of investment contracts with foreign companies. No assurance can be given that such stability and positive economic growth will continue and an overspill of violence and social and political instability from other regions of Iraq and the Turkish border regions of the KRI could have an adverse effect on the KRI s economy. 22

25 Uganda Uganda is among the poorest countries in the world with a predominantly agricultural economy and a history of civil strife and political instability although the country has made significant socio-political improvements in the last two decades. Rural Uganda has an underdeveloped infrastructure and productivity; competitiveness and capital development expenditure are also low. DRC The DRC is an impoverished country with physical and institutional infrastructure that is often in a dilapidated condition. It is in transition from a largely state controlled economy to one based on free market principles and from a non-democratic political system with a centralised ethnic power base to a political system based on more democratic principles. The DRC has historically had high rates of inflation. As the Group will not be able to control the market price at which it sells the oil and gas it produces (except to the extent that it enters into forward sales and other derivative contracts), it is possible that high inflation rates in the DRC in the future could result in an increase in future operational costs in Congolese Francs and have a material adverse effect upon the Group s business, results of operations and financial condition. Pakistan Pakistan has suffered from decades of internal political disputes (including the recent assassination of Benazir Bhutto), low levels of foreign investment, and a costly, ongoing confrontation with neighbouring India. Despite employing International Monetary Fund-approved policies, bolstered by generous foreign assistance, renewed access to global markets and overall decreases in poverty levels by 10 per cent. since 2001, inflation remains the biggest threat to the economy, jumping to more than 9 per cent. in 2005 before easing to 7.9 per cent. in It is possible that high inflation rates in Pakistan in the future could result in an increase in future operational costs in Pakistani Rupees and have a material adverse effect upon the Group s business, results of operations and financial condition. Uncertainties of Legal Systems in Jurisdictions in Which the Group Operates Russia, Uganda, the DRC, the KRI and other jurisdictions in which the Group operates or might operate in the future may have less developed legal systems than more established economies which could result in risks such as (i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or in an ownership dispute, being more difficult to obtain; (ii) a higher degree of discretion and corruption on the part of governmental authorities; (iii) the lack of judicial or administrative guidance on interpreting applicable local rules and regulations; (iv) inconsistencies or conflicts between and within various laws, regulations, decrees, orders, resolutions and judgements; or (v) relative inexperience of the judiciary and courts in such matters. In certain jurisdictions, the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to the Group s licences and business agreements. Some or all of these may be susceptible to revision or cancellation and legal redress may be uncertain, unavailable or delayed. Equally, there can be no assurance that PSCs, concession agreements, joint ventures, licences, licence applications or other legal arrangements will not be adversely affected by the actions of government authorities or others and the effectiveness of and enforcement of such arrangements in these jurisdictions cannot be assured. Failure to Meet Contractual Agreements May Result in the Loss of the Group s Interests Any change in government or legislation may affect the status of the Group s PSCs or contractual arrangements or its ability to meet its contractual obligations and may result in the loss of its interests in its oil and gas properties. Some of the contracts pursuant to which the Group holds an interest in its properties permit the other party to terminate the contract if force majeure conditions cause operations to be economically unviable or interrupted for more than thirty days. Due to the potential for civil unrest in certain countries in which the Group s properties are located, there can be no assurance that these properties will not become subject to force majeure conditions for more than thirty days which could have the consequence of putting those contractual interests at risk. The laws of Jersey do not apply to any of these contractual arrangements and no assurance can be given that these contractual arrangements will be enforced or interpreted in the same manner or to the same extent as would be the case if the laws of Jersey did apply. 23

26 Failure to Follow Corporate and Regulatory Formalities May Call Into Question the Validity of the Entity or its Assets In Russia and other jurisdictions in which the Group may obtain interests, both the conduct of its operations and the steps involved in the Group acquiring its current interests involve or may involve the need to comply with numerous procedures and formalities including in relation to obtaining exploration and production licences. In some cases, failure to follow such formalities or obtain relevant evidence of compliance with such formalities may call into question the validity of the entity or the actions taken. In particular, there are various requirements under the Group s PSCs which, if not complied with could lead to the PSCs being terminated or make them difficult to enforce or rely upon in the local courts to assert the Group s rights and interests, including the minimum expenditure required during the exploration period. Risks Relating to the Group Structure Concentration of Investments in HOC The Company will be the ultimate controlling shareholder of HOC. Assuming full completion of the HOC Subscription, DutchCo will own, 100 per cent. of the HOC Common Shares. The purpose of the Company is to invest (via its wholly-owned subsidiaries) in the entire issued share capital of HOC. On that basis, poor performance by HOC, or adverse events or sentiments in HOC s industry could have a significant adverse effect on the returns received by the Company from HOC and on the price of the Ordinary Shares. Lack of Operating History The Company is a newly formed company incorporated under the laws of Jersey on 6 February 2008 and as such has only a limited operating history. The Company was incorporated on the instigation of HOC for the purposes of a corporate reorganisation through the Plan of Arrangement. Under the Plan of Arrangement the shareholders of the HOC Common Shares have been offered the Ordinary Shares and the Exchangeable Shares in return for their HOC Common Shares. As the Company is newly formed it does not directly hold any assets other than the right of membership in DutchCo, Jersey SubCo and Alberta CallCo, and all the other assets are contained at the Group level. The Rights of Shareholders Under the Laws of Jersey May Differ From the Rights of Shareholders of Companies Incorporated in Other Jurisdictions The Company is incorporated in Jersey under the Act. As a result, the rights of Shareholders will be governed by the laws of Jersey and the Articles. The rights of Shareholders under the laws of Jersey may differ from the rights of shareholders of companies incorporated in other jurisdictions and the enforcement of such rights may involve different considerations and may be more difficult than would be the case if the Company had been incorporated in the jurisdiction of an investor s residence or elsewhere. There May be Difficulty in Enforcing Against The Group s Assets and Judgments Obtained in Jersey Courts While the Company exists under the laws of Jersey and its registered office is located in Jersey, a number of Directors of the Group (other than Mr. Anthony Buckingham and Mr. Paul Atherton who intend to reside in Jersey in the near future) and substantially all of the assets of the Group are located outside Jersey. It may not be possible for holders of Ordinary Shares to effect service of process within Jersey upon the Directors who reside outside Jersey. As such, there may be difficulty in enforcing against the Group s assets, and judgments obtained in Jersey courts based upon the provisions of applicable Jersey securities legislation may not be recognised or enforceable in jurisdictions where certain of the Directors reside or where the Group s assets are located. Risks Relating to the Ordinary Shares and the Exchangeable Shares No Prior Market for the Ordinary Shares and the Exchangeable Shares Prior to the Plan of Arrangement, there will have been no public trading market for the Ordinary Shares or the Exchangeable Shares. Although HOC Common Shares are currently listed and traded on the Toronto Stock Exchange, the Directors can give no assurance that an active trading market for the Ordinary Shares or the Exchangeable Shares will develop or, if it develops, will be sustained following Admission. If an active trading market does not develop or is not maintained, the liquidity and trading price of the Ordinary Shares or the Exchangeable Shares could be adversely affected and investors may have difficulty selling their Ordinary Shares or their Exchangeable Shares. 24

27 Market Price of the Ordinary Shares and the Exchangeable Shares May Fluctuate Significantly The market price of the Ordinary Shares and the Exchangeable Shares may, in addition to being affected by the Group s actual or forecasted operating results, fluctuate significantly as a result of factors beyond the Company s control, including, among others: the results of exploration, development and appraisal programmes and production operations; changes in securities analysts recommendations or estimates of earnings or financial performance of the Company, its competitors or the industry, or the failure to meet expectations of securities analysts; fluctuations in stock market prices and volumes, and general market volatility; changes in laws, rules and regulations applicable to the Company, its operations and the operations in which the Company has interests, and involvement in actual or threatened litigation; general economic and political conditions, including in the regions in which the Group operates; fluctuations and volatility in the prices of oil, gas and other petroleum products; and the Ordinary Shares and Exchangeable Shares may be delisted from the Official List in certain circumstances, including a failure to meet continuing listing obligations of the LSE. Trading Price of the Exchangeable Shares Holders of the Exchangeable Shares, as nearly as practicable, will have the rights that are economically equivalent to the rights of the holders of Ordinary Shares. An application will be made for the admission of the Ordinary Shares and the Exchangeable Shares to listing on the Official List. Since they will be separate listings, the trading prices of the Ordinary Shares and the Exchangeable Shares may not reflect equivalent values. This may result in the holders of Exchangeable Shares having to exchange their Exchangeable Shares for Ordinary Shares in order to maximise the value of their investments prior to a sale. The Major Shareholder Has the Ability to Control Some of the Actions Taken by the Shareholders of the Company As at Admission, the Major Shareholder and Mr. Anthony Buckingham will own and control in aggregate 84,540,340 Ordinary Shares representing approximately 33.2 per cent. of the aggregate voting shares of the Company. As a result of its ownership interest, the Major Shareholder, and thereby Mr. Anthony Buckingham, has the ability to exert significant influence on some of the actions taken by the shareholders of the Company. The Major Shareholder, and thereby Mr. Anthony Buckingham, currently has sufficient voting power to, among other things, delay, deter or prevent a change in control of the Company that might otherwise be beneficial to its shareholders and may also discourage acquisition bids for the Company and limit the amount certain investors may be willing to pay for the Ordinary Shares or the Exchangeable Shares. Each of the Major Shareholder and Mr. Anthony Buckingham have entered into a relationship agreement with the Company dated 28 March 2008 to ensure that the Group is capable of carrying on business independently from the Major Shareholder and that transactions and relationships with the Major Shareholder are at arm s length and on normal commercial terms. There Are Potential Conflicts of Interest to Which the Directors, the Senior Manager and Principal Shareholders of the Company Will be Subject to in Connection With the Operations of the Group There are potential conflicts of interest to which the Directors, the Senior Manager and principal shareholders of the Company will be subject to in connection with the operations of the Group. Some of the Directors, the Senior Manager and principal shareholders are or may become engaged in other oil and gas interests on their own behalf and on behalf of other companies, and situations may arise where the directors and officers will be in direct competition with the Company. Conflicts, if any, will be subject to the procedures and remedies under the Act. The Directors and the Senior Manager of the Company may not devote their time on a full-time basis to the affairs of the Company. Certain Directors and the Senior Manager of the Group own collectively, directly and indirectly, a significant part of the issued share capital of the Company, and will therefore have the possibility to influence the decision-making of the Company. Sales of the Major Shareholder s Ordinary Shares Could Decrease the Market Price of the Ordinary Shares and the Exchangeable Shares As of the date of this document, HOC has proposed the Plan of Arrangement to its shareholders that gives shareholders the ability to exchange their HOC Common Shares for Ordinary Shares or, in certain 25

28 circumstances, for Exchangeable Shares. The shareholders of HOC who elect to exchange their HOC Common Shares for Ordinary Shares or Exchangeable Shares are not subject to any contractual restrictions imposed by HOC or the Company regarding selling their Ordinary Shares or Exchangeable Shares. The Company cannot predict whether substantial numbers of the Ordinary Shares or Exchangeable Shares received by HOC shareholders will be sold in the open market. Sales of a large number of the Ordinary Shares or Exchangeable Shares in the public markets, or the potential for such sales, could decrease the market price of the Ordinary Shares and the Exchangeable Shares and could impair the Company s ability to raise capital through future offerings of Ordinary Shares. As at Admission, the Major Shareholder and Mr. Anthony Buckingham will own and control in aggregate 84,540,340 Ordinary Shares representing approximately 33.2 per cent. of the aggregate voting shares of the Company. The Company cannot predict whether the Major Shareholder or Mr. Anthony Buckingham will sell any of the Ordinary Shares they hold in the open market. Sales by the Major Shareholder or Mr. Anthony Buckingham of a large number of the Ordinary Shares in the public markets, or the potential for such sales, could decrease the trading price of the Ordinary Shares and the Exchangeable Shares, and could impair the Company s ability to raise capital through future offerings of Ordinary Shares. Company s Shareholding Structure May Limit Claims By Shareholders Against Subsidiary Assets The Company holds all of its assets in its wholly-owned (via its indirectly wholly-owned subsidiary, DutchCo) subsidiary, HOC. In the event of insolvency, liquidation or any other reorganisation of HOC, the holders of the Ordinary Shares and Exchangeable Shares will have no right to proceed against the assets of HOC or to cause the liquidation or bankruptcy of that company under applicable bankruptcy laws. Creditors of HOC would be entitled to payment in full from such assets before the Company, as a shareholder, would be entitled to receive any distribution therefrom. Claims of creditors of HOC will have priority with respect to the assets and earnings of HOC over the claims of the Company, except to the extent that the Company may itself (via its indirectly wholly-owned subsidiary DutchCo) be a creditor with recognised claims against HOC ranking at least pari passu with such other creditors, in which case the claims of the Company would still be effectively subordinate to any mortgage or other liens on the assets of HOC and would be subordinate to any indebtedness of HOC. Raising of Future Equity Funds for the Company Could Result in Dilution Depending on future exploration, development, production or acquisition plans, the Group may, after twelve months from the date of this document, require additional financing and the Company may choose to raise such additional finance by way of an equity offering of additional Ordinary Shares. Any such offering may be dilutive to the existing shareholders interests in the Company. In addition, if any outstanding options or convertible bonds are exercised subsequent to Admission, further dilution of the existing shareholders interests in the Company will occur. Payment of Dividends is Subject to the Company Having Sufficient Distributable Reserves The payment of dividends by the Company is subject to the Company having sufficient distributable reserves for such purposes in accordance with Part 17 of the Act. United States and Canadian Shareholders May Not Be Able to Participate in any Future Equity Rights Offering U.S. and Canadian shareholders may not be entitled to exercise pre-emption rights unless the rights and the Ordinary Shares are registered under applicable U.S. or Canadian securities legislation or an exemption from the registration requirements of such legislation is available. The Directors cannot at this time predict whether the Company would seek such registration and the Company would evaluate, at the time of any rights offering, the costs and potential liabilities associated with registration or qualifying for an exemption, as well as the indirect benefits to the Company of enabling U.S. and Canadian shareholders to exercise rights and any other factors the Company considers appropriate at that time, prior to making a decision whether to file a registration statement or prospectus or utilise an exemption from the registration requirements of applicable U.S. and Canadian securities legislation. Jersey Law Significantly Limits the Circumstances Under Which Shareholders of Companies May Bring Derivative Actions The rights afforded to Shareholders will be governed by Jersey law and by the Company s constitutional documents and these rights differ in certain respects from the rights of shareholders in typical U.S. and Canadian corporations. In particular, Jersey law limits the circumstances under which shareholders of companies may bring derivative actions, and, in most cases, only the company can bring an action in respect of any wrongful act committed against it. Under Jersey law derivative actions are available to shareholders of a Jersey company only if all other alternative remedies have been exhausted. In addition, Jersey law does not afford appraisal rights to dissenting shareholders in the form typically available to shareholders of a U.S. or Canadian corporation. 26

29 DIRECTORS, CORPORATE SECRETARY, SENIOR MANAGERS, REGISTERED OFFICE, DIRECTORS AND SENIOR MANAGERS BUSINESS ADDRESSES, HEAD OFFICE, U.K. OFFICE AND ADVISERS Directors Michael Hibberd (Chairman and Non-Executive Director) Anthony Buckingham (Chief Executive Officer) Paul Atherton (Chief Financial Officer) Gregory Turnbull (Non-Executive Director) John McLeod (Non-Executive Director) General Sir Michael Wilkes (Non-Executive Director) Company Secretary Woodbourne Secretaries (Jersey) Limited Ordnance House 31 Pier Road St Helier Jersey JE4 8PW Channel Islands Senior Manager Brian Smith (VP Exploration) Registered Office of the Ordnance House Company 31 Pier Road St Helier Jersey JE4 8PW Channel Islands Head Office and Directors The Parade Business Address St Helier Jersey JE1 1BG Channel Islands U.K. Office of the Company 34 Park Street London W1K 2JD United Kingdom Sponsor JPMorgan Cazenove Limited 20 Moorgate London EC2R 6DA United Kingdom English Legal Advisers to the McCarthy Tétrault Company Registered Foreign Lawyers & Solicitors 2nd Floor 5 Old Bailey London EC4M 7BA United Kingdom Canadian Legal Advisers to the McCarthy Tétrault LLP Company Suite th Avenue S.W. Calgary Alberta T2P 4K9 Canada 27

30 Jersey Legal Advisers to the Company English Legal Advisers to the Sponsor Canadian Legal Advisers to the Sponsor Auditors and Reporting Accountants of the Company Auditors of HOC Registrars of the Company Principal Bankers of the Company Independent Petroleum Engineering Consultants to the Company Voting Trustee for the Special Voting Share in the Company Mourant du Feu & Jeune 22 Grenville Street St Helier Jersey JE4 8PX Channel Islands Linklaters LLP One Silk Street London EC2Y 8HQ United Kingdom Stikeman Elliott LLP Dauntsey House 4B Frederick s Place London EC2R 8AB United Kingdom KPMG LLP U.K. 8 Salisbury Square London, EC4Y 8BB United Kingdom KPMG LLP Canada National Local Suite th Avenue S.W. Commerce Court West Bow Valley Square II 199 Bay Street Calgary, Alberta Toronto, Ontario T2P 4K9 M5L 1B2 Canada Canada Computershare Investor Services (Channel Islands) Limited Ordnance House 31 Pier Road St Helier Jersey JE4 8PW Channel Islands Royal Bank of Canada (Canada) Standard Bank (Europe) Bank of Scotland (Europe) RPS Energy Goldsworth House Denton Way Goldsworth Park Woking Surrey GU21 3LG United Kingdom Computershare Trust Company of Canada Suite th Avenue S.W. Calgary Alberta T2P 3S8 Canada 28

31 EXPECTED TIMETABLE OF PRINCIPAL EVENTS Plan of Arrangement becomes effective and the Company becomes the ultimate holding company of the Group (1) March 2008 Admission and expected commencement of dealings in the Ordinary Shares on the London Stock Exchange am on 31 March 2008 Ordinary Shares credited to CREST accounts March 2008 Last day of dealing in the HOC Common Shares... 2April 2008 De-listing of HOC Common Shares from TSX... 2April 2008 Admission and expected commencement of dealings in the Exchangeable Shares on the London Stock Exchange am on 2 April 2008 Listing of Exchangeable Shares on TSX... 2 April 2008 Despatch of definitive share certificates (where applicable)... The week commencing 7 April 2008 Notes: (1) These dates are indicative only and will depend, among other things, on the date upon which the Court sanctions the Plan of Arrangement. All times are London times unless specifically stated otherwise. Each of the times and dates in the above timetable are subject to change without further notice. 29

32 FORWARD-LOOKING STATEMENTS AND OTHER INFORMATION This document includes statements that are, or may be deemed to be forward-looking statements. The words believe, anticipate, expect, intend, aim, plan, predict, continue, assume, positioned, may, will, should, shall, risk and other similar expressions that are predictions of or indicate future events and future trends identify forward-looking statements. These forward-looking statements include all matters that are not historical facts. In particular, the statements under the headings Summary, Risk Factors, Business and Operating and Financial Review regarding the Group s strategy, plans, objectives, goals and other future events or prospects are forward-looking statements. An investor should not place undue reliance on forward-looking statements because they involve known and unknown risks, uncertainties and other factors that are in many cases beyond the Group s control. By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. The Company cautions investors that forward-looking statements are not guarantees of future performance and that its actual results of operations, prospects, financial condition and liquidity, and the development of the industry in which it operates, may differ materially from those made in or suggested by the forward-looking statements contained in this document. The cautionary statements set forth above should be considered in connection with any subsequent written or oral forward-looking statements that the Group, or persons acting on its behalf, may issue. Factors that may cause the Group s actual results to differ materially from those expressed or implied by the forward-looking statements in this document include but are not limited to the risks described under Risk Factors. Presentation of Financial and Statistical Information Presentation of Financial Information Financial information in relation to the Group means, for the purposes of this paragraph, the information in this document which has been extracted without material adjustment from Part VII of this document. Selected financial information is extracted from the audited consolidated financial statements of HOC for the three years ended 31 December 2004, 31 December 2005 and 31 December 2006 and the nine-month period ended 30 September 2007 and from the unaudited consolidated financial statements of HOC for the nine-month period ended 30 September 2006 as set out in Part VII of this document and is to be found in the Selected Financial Information section and Part IV of this document. Investors should ensure that they read the whole of this document and not just rely on key information or information summarised within it. The consolidated financial statements in Part VII(B) of this document for the two years ended 31 December 2005 and 31 December 2006 and the nine-month period ended 30 September 2007 and for the nine-month period ended 30 September 2006 were prepared in accordance with IFRS and the consolidated financial statements in Part VII(C) of this document for the years ended 31 December 2004 and 31 December 2005 have been prepared in accordance with Canadian GAAP. A statement of reconciliation highlighting the differences in the financial statements prepared in accordance with Canadian GAAP and the financial statements prepared in accordance with IFRS, both for the year ended 31 December 2005, is contained in the notes to the financial statements prepared in accordance with IFRS. The significant IFRS accounting policies applied to the financial information of the Group, for the two years ended 31 December 2005 and 31 December 2006 and the nine-month period ended 30 September 2007 have been applied consistently in Part VII of this document. The significant Canadian GAAP accounting policies applied to the financial information of the Group, as applicable, for the financial years ended 31 December 2004 and 31 December 2005 have been applied consistently in the financial information in Part VII of this document. IFRS differs in certain material respects from Canadian GAAP. Except as stated above, the Group has not prepared and does not currently intend to prepare its financial statements in, or reconcile them to, Canadian GAAP. In making an investment decision, prospective investors must rely on their own examination of the Group and the financial information in this document. Prospective investors should consult their own professional advisers for an understanding of the differences between Canadian GAAP and IFRS. 30

33 Currencies All references in this document to Pounds Sterling, Pounds,, p or pence are to the lawful currency of the United Kingdom. All references in this document to $, Dollars, dollar(s), U.S.$ and U.S. cent(s) are to the lawful currency of the United States, unless otherwise specified. All references in this document to Cdn$, C$ or Canadian cents are to the lawful currency of Canada. Percentages Percentages in tables in this document have been rounded and accordingly may not add up to 100 per cent. Certain financial, statistical and operating data has been rounded. As a result of this rounding, the totals of data presented in this document may vary slightly from the actual arithmetic totals of such data. Operating Information Any unaudited operating information in relation to the Group s business is derived from the following sources: (i) management accounts for the relevant accounting period presented directly from the Group s accounting system (based on invoices issued and/or received); (ii) internal financial reporting systems supporting the preparation of financial statements; (iii) management assumptions and analyses and (iv) discussions with key operating personnel. Operating information derived from management accounts or internal reporting systems in relation to the Group s business is to be found principally in Part V of this document. Production Figures All references in this document to production are to such stated production figures that are net to the Group unless specified otherwise. Presentation of Reserves and Resources All references to reserves and resources are to proved and probable in the case of reserves and contingent and prospective in the case of resources. Forecasts of reserves and associated net production revenues are forward-looking statements based on judgments regarding future events. The accuracy of reserves estimates and associated economic analysis is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. This document should be accepted with the understanding that reserves and financial performance subsequent to the date of the estimates may necessitate revision. These revisions may be material. All reserves are quoted as the Group s net entitlement interest, which is net of any applicable State royalties. In the case of properties within PSC areas, the Group s net entitlement to cost oil and profit oil according to the terms of the PSC assuming forecast price and cost assumptions as evaluated in reports prepared by RPS. For information purposes, reserves are also presented as the Group s working interest share before deduction of State royalties where applicable. Information in respect of gross and net acres, well-counts and production are as at 30 September 2007, unless indicated otherwise. RPS has evaluated (on the basis set out below) the Group s interest in reserves of crude oil and gas in the Group s properties. All estimates of present value are stated prior to provision for indirect costs and calculated after all local country income taxes but prior to the deduction of income taxes in the U.K., Jersey, Canada or elsewhere. The Company s most recent reserves disclosure, dated 31 March 2008, prepared in accordance with the PRMS has been reproduced in its entirety in Part III of this document and is defined, for the purposes of this document, as the Technical Report. The Technical Report was commissioned by the Company and was prepared specifically for the purposes of this document but it has not been amended or updated for the purposes of its inclusion in this document. The Technical Report is a statement of the estimated oil and gas reserves attributed to the Company as at 30 September This estimate is based on technical information supplied by the Company to RPS. The technical information supplied by the Company to RPS was not independently verified by RPS and is the responsibility of the management of the Company. In accordance with usual standard industry practice, all technical information that was obtained from the Company or from public sources was accepted, without 31

34 further investigation. It is RPS s opinion that the technical information received from the Company was reasonable, based on similar evaluations prepared by RPS. RPS used the technical information to produce the reserves and resource estimates which formed the basis of the Technical Report. The reserves estimates comprise the proved, probable and possible reserves and related estimated future net revenues which are based on the technical information, and continues to be the responsibility of the Board. The reserves and resources were estimated by RPS in accordance with standards set out in the PRMS. Having carried out the evaluation on the basis set out above, RPS has provided an independent reserves and resource estimates which have been determined and presented in accordance with the PRMS. General IMPORTANT INFORMATION Each of the Ordinary Shares and the Exchangeable Shares have not been, and will not be, registered under the securities laws of either Japan or Australia, or any other jurisdiction although the Company will be a reporting issuer in the Provinces of Alberta, British Columbia and Ontario in Canada and regulatory clearance has been sought in Jersey. No regulatory clearances in respect of the Ordinary Shares have been, or will be, applied for in any jurisdiction other than the U.K. This document does not constitute an offer to sell, or the solicitation of an offer to subscribe for or buy, any Ordinary Shares or the Exchangeable Shares to any person in any jurisdiction to whom or in which such offer or solicitation is unlawful and is not for distribution in or into the United States of America, Australia or Japan. No action has been or will be taken in any jurisdiction, other than the U.K., that would permit a public offering of the Ordinary Shares or the Exchangeable Shares, or possession or distribution of this document or any other offering material, in any country or jurisdiction where action for that purpose is required. Accordingly, the Ordinary Shares or the Exchangeable Shares may not be offered or sold, directly or indirectly, and neither this document nor any other offering material or advertisement in connection with the Ordinary Shares or the Exchangeable Shares may be distributed or published in or from any country or jurisdiction except under circumstances that will result in compliance with any applicable rules and regulations of any such country or jurisdiction. Any 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 to subscribe for or buy any of the Ordinary Shares or the Exchangeable Shares described herein to any person in any jurisdiction to whom it is unlawful to make such offer or solicitation in such jurisdiction. United States The Ordinary Shares and the Exchangeable Shares have not been and will not be registered under the United States Securities Act of 1933, as amended (the US Securities Act ) and may not be offered or sold within the United States except pursuant to an applicable exemption from, or in a transaction not subject to the registration requirements of the US Securities Act, and in compliance with any applicable securities laws of any state or other jurisdiction of the United States. In addition, until 40 days after the commencement of the offering of Ordinary Shares and the Exchangeable Shares an offer or sale of the Ordinary Shares or the Exchangeable Shares within the United States by any dealer (whether or not participating in the offering) may violate the registration requirements of the US Securities Act. Websites The Company s and HOC s websites are or The information on these websites or any website mentioned in this document or any website directly or indirectly linked to these websites has not been verified and is not incorporated by reference into this document and investors should not rely on it. 32

35 PART I INFORMATION ON THE GROUP OVERVIEW 1. INTRODUCTION The Company was incorporated in Jersey on 6 February 2008 to be the ultimate holding company of the Group. The Group was established in 1992 (with HOC being incorporated on 30 October 1996) as an independent upstream exploration and production group engaged in the exploration for, and the development, production and acquisition of, oil and gas in its core areas of Africa, the Middle East and Russia. HOC, being a member of the Group and in anticipation of the Admission, has proposed a reorganisation of its share capital. The reorganisation will culminate in the creation of the Exchangeable Shares which will be subject to voting rights and terms and conditions different from the Ordinary Shares but which, subject to certain conditions, will be exchanged for Ordinary Shares on a one-to-one basis. HOC intends to (at or immediately following Admission) procure the admission of the Exchangeable Shares to trading on both the TSX and on the Official List together with admission to trading on the London Stock Exchange s main market for listed securities. See Corporate Reorganisation Part IX of this document for further information on the reorganisation of HOC s share capital and the voting and other rights attaching to the Exchangeable Shares and see Additional Information in section 6.3 of Part X for further information on the terms and conditions attaching to the Exchangeable Shares. The Group has exploration projects in Uganda, the KRI, the DRC, Malta, Pakistan and Mali, and producing properties in Oman and Russia. The Group s management team believes that it has demonstrated a track-record of finding new substantial discoveries, particularly in Africa, including the hydrocarbon system in the Albert Basin, Uganda and the M Boundi oilfield in Congo. The Group s producing, development and exploration projects, together with potential opportunities, provide a combination of early cash flow and longer term value-creation opportunities for its shareholders. See History and Development in section 9 of Part I of this document and Intercorporate Relationships in section 11 of Part I of this document for further information on the origins of the Group and its development. All references in this Part I of the document to production are to such stated production figures that are net to the Group unless specified otherwise. 2. SUMMARY OF GROUP ASSETS The Group has a portfolio of production, development and exploration assets focussed on Africa, the Middle East, Russia and the Mediterranean. Management has focussed the Group s efforts on large areas with multiple drilling opportunities. The Group s two producing assets are located in Russia and Oman. The Group has a producing interest in the Khanty-Mansiysk Region of West Siberia with 60.5 million bbls proved and probable reserves net to the Group and average production of 342 bopd in February The Group is the operator of this asset and holds a 95 per cent. interest. The asset in Oman, the Bukha field, located approximately 40 km offshore in the Straits of Hormuz, has proved and probable reserves of 0.15 million bbls (based on the Group s entitlement interest) and net production is 109 bopd as at January The operator is RAK Petroleum and the Group has a 10 per cent. interest. The West Bukha discovery is also located in Oman, where a well was successfully drilled in The first phase of the West Bukha development has commenced and comprises design, fabrication and installation of the wellhead platform and pipeline with a tie into the Bukha facilities. Management believes that production, subject to unforeseen circumstances, is likely to commence in the third quarter of 2008 and an agreement is in place to sell the gas from the West Bukha field to Rakgas for five years. The Group s reserves for West Bukha (entitlement interest) were estimated at 1.5 bcf of gas and 1.25 MMboe of oil, condensate and LPG by RPS as at 30 September The Group also holds assets in the Albert Basin in Uganda, as operator with a 50 per cent. working interest in Block 3A and as operator with a 50 per cent. interest in Block 1. The assets are currently in the appraisal and exploration stages, however, management is confident about the opportunities in the Albert Basin. RPS has certified that the Group had a 50 per cent. working interest share of the mean risked working interest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at 30 September The Government of Uganda has a back-in right which could, if exercised, reduce the Group s working interest to 42.5 per cent. In the event that these resources were to mature into reserves 33

36 these barrels would be subject to the PSC arrangements in Blocks 3A and 1 and result in net entitlement reserves that reflect those arrangements. In October 2007, the Group executed a PSC with the KRI government over the Miran Block, which covers an area of 1,105 square km and is located only 55 km from the Kirkuk oilfield. The Group also entered into a separate strategic agreement with the KRG to establish a 50/50 joint venture company which shall build, own and operate an oil refinery in the vicinity of the licence. In addition, the Group has been awarded or farmed into licences in Mali, Pakistan and Malta and management continue to pursue other opportunities in accordance with the acquisition criteria set out in Strategy in section 5 of this Part I below. 3. SUMMARY OF GROUP RESERVES AND RESOURCES RPS has certified that as of 30 September 2007, the Group s net working interest and entitlement reserves and value, using money of the day prices, discounted at 10 per cent., were as follows: Net Working Net Net Interest Entitlement Present Reserves Reserves Value MMboe MMboe $Millions Proved Probable Additional Total Proved + Probable Total Proved + Probable + Possible RPS has certified that the Group had a 50 per cent. working interest share of the mean risked working interest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at 30 September The Government of Uganda has a back-in right which could, if exercised, reduce the Group s working interest to 42.5 per cent. In the event that these resources were to mature into reserves these barrels would be subject to the PSC arrangements in Blocks 3A and 1 and result in net entitlement reserves that reflect those arrangements. 4. GROUP STRENGTHS AND COMPETITIVE ADVANTAGES The Directors believe that the Group has a number of key strengths and competitive advantages that are important to the continued success of the business. The Group believes that its key strengths are as follows: Ability to secure a portfolio of high-impact international plays The Group has a track-record of delivering growth in shareholder value through its strategy of focusing on high-impact international plays containing multiple targets with the potential to discover large reserves of oil. The Group s current focus areas are the Lake Albert region in Uganda and the DRC, the KRI and West Siberia where it has sourced and secured properties as a result of a number of factors. The Group adopts a methodology for appraising potential opportunities centred around the appreciation and management of technical and political risk. This approach, together with the experience of the Group s management and technical teams, has enabled the Group to identify and be amongst the first international oil companies to hold interests in territories such as Uganda, the eastern DRC and in recent times, the KRI. The Group has a proven track-record in sourcing deals, and has demonstrated its first-mover advantage in acquiring many of its assets resulting from the hands-on approach, flexibility and speed of the Group s management team. The Group s management team has demonstrated its ability to make substantial oil discoveries and its flat and lean structure has enabled the Group to enjoy first-mover advantage in many of its deals and to take advantage of interesting opportunities, such as the KRI and the Albert Basin in Uganda. 34

37 Strong management and technical teams The Group s management and technical team has a track-record of finding attractive oil discoveries, including the hydrocarbon system in the Albert Basin in Uganda and the M Boundi field in the Congo. The Group leverages off a highly effective network of influential industry, political and institutional relationships. These relationships enable the Group to form strategic alliances which reduce resource commitments and lower exploration and development risk, as well as give the Company access to properties. Diversified portfolio of assets The Group has built a diversified portfolio of assets by geography, product and development stage. Geographically the Company s portfolio is spread between the Group s core areas of focus of Africa, the Middle East and Russia. In addition, the Group may from time to time invest in additional opportunistic plays, outside of these core geographies, if management believe that individual plays will enhance shareholder value. Examples of investments in such opportunities include the Group s recently acquired interests in Malta and Pakistan. As detailed in section 6 of this Part I, the Group s portfolio contains a spread of existing production, reserves and resources between oil, gas, condensate and LPG. Furthermore, the Group s assets are well spread across the development cycle. The Group currently has producing assets in Oman and the Zapadno Chumpasskoye licence in Western Siberia, a development property in Oman, together with exploration and appraisal properties in Uganda, the KRI, the DRC, Malta, Mali and Pakistan. Presence in the Albert Basin in Uganda The Albert Basin in Uganda is considered by management to have the potential to contain significant quantities of oil. Assets in the Albert Basin in Uganda are controlled by the Group and Tullow, with the Group partnered with Tullow on Blocks 3A and 1. Eight successful exploration and appraisal wells have been drilled in the basin since the beginning of 2006 with each of these wells having encountered oilbearing reservoirs. Of these, two wells tested at over 12,000 bopd. Further information is provided in section 6 of this Part I. First production is targeted by management to commence in the medium term, with potential production estimated to be in excess of 100,000 bopd in the medium term. An additional benefit of the Group s presence in the Albert Basin is the proximity of its interests in Blocks 1 and 2 on Lake Albert in the DRC to the adjacent Blocks 3A and 1 on the Ugandan side of the DRC/Uganda border. The potential exists for both assets to benefit from the proposed construction of an international export pipeline from Lake Albert to Mombasa on the east coast of Kenya. First-mover advantage in Kurdistan The Group was one of the first international oil companies to be awarded a PSC in the KRI. The Group executed a PSC with the KRG over the Miran Block in the KRI on 2 October The Group has been appointed operator. The Group has also entered into a separate strategic agreement with the KRG to establish a 50/50 joint venture company which shall build, own and operate an oil refinery in the vicinity of the Miran Block. The refinery, which should have a capacity of 20,000 bopd, is scheduled to be operational to design specification within approximately two years of the signing of the agreement. Historic track-record of creating value and generating cash to finance new developments Historically, the Group has sold certain assets, notably in the Republic of Congo to create value for shareholders and generate cash which has been used to finance the development of other oil and gas assets in the core areas. Further detail is provided in History and Development in section 9 of this Part I. Strong financial position The Directors believe that the Group has a strong financial position as a result of the proceeds from the completion of the private placement of $165.0 million of convertible bonds in February 2007 and the primary equity fundraising of Cdn$181.5 million completed in November The Group intends to use the net proceeds of its recent equity fundraising to fund exploration and development activities, potential strategic acquisitions, as well as for general working capital purposes. 35

38 5. STRATEGY Strategy The Group aims to continue to generate further growth in shareholder value by focusing on high-impact international plays containing multiple targets with the potential to discover substantial reserves of oil. The Group s growth strategy is to acquire and invest in and then to explore and develop oil and gas properties throughout the world, with a particular emphasis on its core areas of Africa, the Middle East and Russia. The Group believes that it has developed a highly effective network of influential industry, political and institutional relationships, enabling it to gain access to a wide variety of new oil and gas business opportunities and can provide the Group the competitive capability necessary to generate continued growth for the Group. The Group believes that major oil companies, in the course of exploring large tracts of international acreage, frequently choose to ignore or abandon smaller discoveries, or discoveries with special infrastructure requirements. Comparatively smaller organisations, such as the Group, without the overhead structures of larger organisations can often, through careful due diligence, planning and local intelligence, acquire and convert such discoveries into economic and profitable developments. The Group has obtained a range of interests, most recently in the KRI, Mali, Malta and Pakistan. The Group s exploration strategy is to continue to focus on minimising financial exposure of the Company through effective portfolio management including industry farm-outs and the acquisition of working interests. The tenets of the strategy are: identifying and accessing land deals that offer potential for high quality oil and gas prospects; creating internally-generated geological and geophysical hydrocarbon prospects; evaluating and considering participation in projects created by industry partners; developing and maintaining a portfolio of low-to-medium-risk drilling opportunities; operating prospects, to the extent possible, to control timing and expense levels or maintaining a close association with the operating company; and pursuing projects with near-term on-stream characteristics to create cash flow. The Group s strategic process involves acquiring properties, and developing its properties through well and facility optimisation, completions and development drilling. Once established in an area, the Group pursues additional development and exploratory drilling in the surrounding area. Environmental, corporate and social responsibility Respect for the environment and active engagement with local communities are fundamental to the business of the Group. The Group s objective is to minimise its impact on the environment and to undertake a series of community, conservation and education projects in certain countries in which it operates. Historic or ongoing projects include building a school in the Lake Albert region, road building and rehabilitation of roads to improve access to local markets, drilling of community water wells, provision of medical supplies and health checks, sponsorship of the Save the Rhino Fund and sponsorship of local individuals attendance at universities. Acquisition Strategy When reviewing potential property acquisitions, the Group considers, amongst other things, the following criteria: the ability of the Group to enhance the value of a property through additional development and exploratory drilling, completion and tie-in of capped wells, additional exploitation efforts, including improved production practices, and improved marketing arrangements; the quality of production and reserves, in terms of product type, production rates, stability of production, reserve life index and operating cost; the economic potential of a property to yield a rate of return greater than 20 per cent., with a capital payout of less than five years; the high-impact nature of an exploration programme and whether it has the possibility of finding significant quantities of hydrocarbons; the compatibility of a property with management s organisational skills, capabilities and the Group s existing portfolio; 36

39 the availability of existing infrastructure and the ability to expand that infrastructure in order to increase production; the potential for a multi-zone hydrocarbon opportunity; the ability to be appointed as an operator; the degree of control gained over operations and development, and the potential for the Group to become the operator; and the ability to efficiently bring a property s production to market in the near-term. The Directors may, in their discretion, approve asset or corporate acquisitions or investments that do not conform to all of these guidelines based upon the board s consideration of the qualitative aspects of the subject properties including their risk profile, technical upside, reserve life and asset quality. 6. THE BUSINESS Introduction The Company, through its subsidiaries, is actively engaged in the exploration for, and the development, production and acquisition of, oil and gas interests in Russia, the Middle East, Africa and the Mediterranean. Currently the principal areas of focus are Uganda, the KRI and West Siberia. The table below summarises the Group s production properties. Proved plus Group probable Property Block Working Designated reserves Country Name number Interest Operator (MMboe) Oman... Bukha Block 8 10% RAK Petroleum 0.15 Russia... Zapadno Zapadno 95% The Group 60.5 Chumpasskoye Chumpasskoye The table below summarises the Group s development properties. Proved plus Group probable Property Block Working Designated reserves Country Name number Interest Operator (MMboe) Oman... West Bukha Block 8 10% Rak Petroleum 1.5 The table below summarises the Group s exploration property. Group Block Working Designated Country number Interest Operator Uganda... Block 3A 50% The Group Uganda... Block 1 50% The Group KRI... Miran 100% The Group DRC... Block % Tullow DRC... Block % Tullow Mali... Block 7 75% (1) The Group Mali... Block 11 75% (2) The Group Malta... Area 2 100% The Group Malta... Area 7 100% The Group Pakistan... Block No % The Group (Sanjawi) E/L (1) This working interest can be earned by the Group by financing 100 per cent. of the minimum work programme over the next two years. (2) This working interest can be earned by the Group by financing 100 per cent. of the minimum work programme over the next two years. Overview of the Group s Properties The following is a description of the oil and gas properties, plants, facilities and installations in which the Group has an interest and that are material to the Group s operations and exploration activities, categorised by geographic region. 37

40 Russia Russia has the largest gas reserves and the eighth largest oil reserves in the world, estimated at 60 billion bbls and 1,700 trillion cubic feet of gas (according to estimated figures stated in the CIA World Factbook as at 1 January 2006). The Western Siberian region, where the Zapadno Chumpasskoye field is located, accounts for more than 60 per cent. of Russia s oil production. There is increasing international investment in the Russian oil and gas industry. Map of Zapadno Chumpasskoye Licence and Surrounding Area W E S T E R N S I B E R IA ZAPADNO CHUMPASSKOYE LICENCE km LEGEND Heritage PSA Fields Oil Pipelines Gas Pipelines Exploration & Appraisal Well 14MAR

41 In 2005, the Group acquired a 95 per cent. equity interest in ChumpassNefteDobycha, a Russian company whose sole asset is the Zapadno Chumpasskoye licence, an exploration permit previously held by TNK-BP. The field is located in West Siberia in the province of Khanty-Mansiysk, approximately 100 km from Nizhnevartovsk in the vicinity of TNK-BP s prolific Samotlor field. The licence, which expires on 7 September 2024, has an area of approximately 200 square km and contains a field which was discovered in Zapadno Chumpasskoye has net 60.5 million bbls proved & probable reserves independently certified by RPS and current production is approximately 342 bopd. Initial production facilities were commissioned in May 2007, following which production commenced on 14 May Zapadno Chumpasskoye is located close to well-developed infrastructure in West Siberia and an oil pipeline runs through the licence area for which the Group has negotiated certain access rights. It is the Group s intention to build its presence around this area, which is attractive because of its resource potential and existing infrastructure. Nine wells had been drilled in the licence area prior to acquisition by the Group. The reservoir is a sandstone of late Jurassic age at a depth of approximately 2,700 metres. The work programme in the licence includes a commitment to drill no less than three wells (which the Group has already satisfied). As operator of the licence, the Group has built an operational and technical team consisting of 39 employees in Nizhnevartovsk, Russia with experience of working in the region, acquired 200 km of 2D seismic, undertaken certain civil works to build a drilling pad and roads, acquired certain early production equipment, drilled three wells and re-entered and brought existing well #226 into production. Capital expenditure in Russia between 2005 and 2007 (IFRS) may be summarised as follows: Nine-month period ended Year ended 31 December 30 September $ $ $ $ (Unaudited) Drilling... 5,590,214 Seismic... 1,345,524 1,373,001 Other (1)... 6,080,697 11,236,331 4,338,516 8,645,083 6,080,697 12,581,855 5,711,517 14,235,297 (1) Such figure includes the acquisition costs of the licence in Production from the field commenced in 2007, and management estimate could increase to a peak of approximately 16,000 bopd in Total gross development costs of the field are estimated at over $400 million and are estimated to be incurred up to 2015, with peak expenditure expected in 2009 and Independent Reserves at the Zapadno Chumpasskoye Field RPS estimated the Zapadno Chumpasskoye field s net working and entitlement interest reserves and value to the Group as at 30 September 2007, using money of the day prices, discounted at 10 per cent., to be as follows: Net Net Net Working Entitlement Present Interest Interest Value MMboe MMboe $Millions Proved Probable Additional Total Proved + Probable Total Proved + Probable + Possible The Group s Russian strategy is to acquire a series of development licences at attractive prices to allow the Group to generate early cash flow and production. The Group established a jointly owned company with TISE Holding Company, TISE-Heritage Neftegas, in The other shareholders of TISE Holding Company include Concord, Zarubejneft, Zarubejneftegas (a wholly-owned Gazprom subsidiary), Technopromexport and Zarubejstroymontaj. TISE-Heritage Neftegas was formed to appraise and acquire oil and gas opportunities in Russia and internationally. 39

42 Oman The energy sector of Oman accounts for the majority of its export earnings and government revenue. Oman has current proved hydrocarbon reserves of approximately 5.5 billion bb1s and 795 billion m 3 gas with current production of approximately 740,000 bopd and approximately 50 million m 3 /day gas. Current consumption is some 66,000 bopd and 2.4 million m 3 /day gas. The gas sector in Oman is considered to be the cornerstone of the government s economic growth strategy and great efforts have been made to turn gas into a thriving export industry and in excess of some 10 billion m 3 are exported annually (all of the above figures are stated in the CIA World Factbook as at 1 January 2006). Map of Block 8 and West Bukha Field and Surrounding Area IRAN Gavarzin Salakh Qeshm Island Straits of Hormuz West Bukha Field BLOCK 8 Bukha Field Mubarek Field Khor Khwair Processing Plant OMAN Ras Al Khaimah LEGEND Heritage PSA Oil Fields U.A.E Gas Fields Gas Condensate Field Oil & Gas Well Dubai Pipelines Processing Plant International Border OMAN 0 100km 14MAR

43 The Group acquired a 10 per cent. interest in Block 8 offshore of Oman in The other joint venture partners are RAK Petroleum (the operator) with a 40 per cent. interest and LG International with a 50 per cent. interest. This licence has an area of 423 square km and contains the Bukha field which is located 40 km offshore in the Straits of Hormuz and is a gas-condensate field, in around 90 metres of water. The licence also contains the West Bukha discovery. The Group has proved and probable reserves of 1.6 million barrels of oil equivalent of liquids and gas in Oman, independently certified by RPS and net production for January 2008 was approximately 109 bopd. The Bukha field commenced production of gas and condensate from two wells in Wet gas is produced through an unmanned platform and channelled via a 34 km pipeline to an onshore plant in Ras Al Khaimah. Revenue is generated from selling the condensate and LPG. Overall, gross production of liquids from the Bukha field declined by 11 per cent. to 1,618 bopd in 2007, which is in line with expectations for this mature asset. Production is piped into a processing plant onshore in Ras Al Khaimah, operated by the state gas company, Rakgas. There the gas condensate is stored for subsequent lifting when logistically economic quantities are accumulated and sold to a third party under an annual contract. LPG is sold to Rakgas and the residual gas is sold by Rakgas to local cement factories. The Company is not paid directly for the gas production from the Bukha field, but will receive revenue from gas production from the West Bukha field. Block 8 also contains the Hengam/West Bukha discovery, which represents a significant potential future field development. The field is partially located in Block 8 in Oman, approximately 20 km from the Bukha field, but a significant part of the structure is in neighbouring Iranian waters, where it is known as Hengam. In May 2006, the West Bukha-2 appraisal/development well was spud, targeting cretaceous-age carbonates (the same formations as at Bukha) in a large, gas-condensate accumulation straddling the Oman-Iran border. This well was a success and tests produced a combined flow-rate from the zones tested (Ilam/ Mishrif/Mauddud and Thamama) of approximately 12,750 bopd and 26 MMscf/d. The oil was light (approximately 42 o API). Development of the West Bukha field commenced in 2007 and is ongoing. It is planned to re-enter the West Bukha 2 well and complete it as a producer. Facilities design work has been concluded and it is planned to install a platform and pipeline to deliver the petroleum fluids to markets in Ras Al Khaimah via the Bukha system. First commercial production is anticipated in the third quarter of Capital expenditure in Block 8 between 2005 and 30 September 2007 (IFRS) may be summarised as follows: Year ended Nine-month periods ended 31 December 30 September $ $ $ $ (Unaudited) Drilling... 3,209,500 2,621, ,862 Seismic , ,192 88,897 Other , , ,115 1,982, ,316 4,327,599 3,186,921 2,821,408 Independent Reserves at Bukha Field in Block 8 RPS estimated the net working interest reserves and net entitlement interest and value to the Company of West Bukha and Bukha as at 30 September 2007, using money of the day prices, discounted at 10 per cent., to be as follows: Net Working Net Net Interest Entitlement Present Reserves Interest Value MMboe MMboe $Millions Proved Probable Additional Total Proved + Probable Total Proved + Probable + Possible Uganda Significant oil exploration began in Uganda in 1997 following the award of an oil and gas licence to the Group. Assets in the Albert Basin are controlled by the Group and Tullow Oil plc. The Albert Basin is located on the border with the DRC. 41

44 The Ugandan government has stated that it wishes to achieve early production as a stepping stone to Uganda s economic growth to reduce reliance on imports and there has been some initial discussion about an export pipeline to run to Mombasa in Kenya depending on commercial viability. Discovery of a multihundred-million-barrel oil or condensate field could justify a pipeline to the Kenyan coast. A smaller discovery of hydrocarbons might lead to the establishment of a regional oil and gas industry to displace high-cost imported products or to be used for power generation. Map of Blocks 3A and 1 and Surrounding Area LEGEND SUDAN Permits Albert Graben Heritage PSA Oil Wells Country Border BLOCK 5 Neptune Prospect Oil Field BLOCK 1 Heritage D. R. C. BLOCK 2 Tullow BLOCK 3A Heritage UGANDA BLOCK 3B Open BLOCK 3C Open BLOCK 3D Open BLOCK 4B Dominion BLOCK 4A Open RWANDA LEGEND Licence Boundary Heritage PSA International Border + B A S E M E N T Albert Graben Rwenzori Mountains Semliki D. R. C 50km Turaco Block 3A TANZANIA Blue Mountains D. R. CONGO UGANDA Pelican Prospect + Block + 3C Open Block 3D Open Lake Albert Waraga-1 Ngassa-1 Mputa-2 Kingfisher-1 + B A S E M E N T Block 3B Open Mputa-1 Mputa-4 Nzizi-1 Mputa-3 Nzizi-2 + UGANDA 14MAR

45 The Group is the operator and has a 50 per cent. interest in two exploration licences in the hydrocarbon system in Lake Albert, Uganda. The Group has had interests in Uganda since The Directors believe that the Albert Basin in Uganda represents an exciting opportunity with a potential to discover significant quantities of oil. The assets in the Albert basin are controlled by the Group and Tullow Oil plc. Eight exploration and appraisal wells have been drilled successfully in the basin since the beginning of 2006 and all have encountered oil bearing reservoirs with two of the wells testing at over 12,000 bopd. It is currently anticipated that potential production could be in excess of 100,000 bopd in the medium-term. The Group is the operator of Blocks 3A and 1. Blocks 3A and 1 are located in a sedimentary basin known as the Albert Basin in the western arm of the East African rift valley, straddling the border with the DRC. Approximately 80 per cent. of Block 3A covers the south-eastern part of Lake Albert and the remainder is found in the onshore Semliki flats area to the south of the lake. The Block 3 licence was awarded in 1997 and after drilling three test wells at the same Turaco drill site, which were not considered commercial discoveries, all of the area was subsequently relinquished. Block 3A, originally encompassing most of the exploration acreage which previously constituted Block 3, was re-licensed in 2004 for a term of six years. Block 3A now covers an area of 2,033 square km. Energy Africa (now owned by Tullow) farmed-in to the licence in August 2001, acquiring 50 per cent. in return for funding a seismic survey and partly funding the costs of a well. The licence for Block 1 extends over an area of almost 3,659 square km and was awarded pursuant to the PSC entered into by the Group with the Government of Uganda on 1 July Under the terms of the PSC, the Group will act as operator. According to the Block 1 and Block 3A PSC in Uganda, the Government of Uganda may elect to enter into a joint venture agreement, at any time, for up to 15 per cent. participation in the properties and the associated production. The Company has not received any indication from the Government of Uganda that it intends to invoke this election. The Group has agreed to a total minimum contractual work programme comprising the acquisition of at least 150 km of seismic data and the drilling of up to three exploration wells. The total minimum financial commitment amounts to $12.5 million spread over three separate two year exploration periods. The Kingfisher deviated well in Block 3A spud in August 2006 and drilled to a total depth of 3,195 metres, which was determined to be close to the limit of the rig s operational capability. Four intervals were tested successfully in the Kingfisher well, resulting in an overall cumulative flow rate of 13,893 bopd through a one inch choke. A shallower interval, at a depth of 1,783 metres, was tested successfully in November 2006, producing 4,120 bopd over a 10 metre interval. The tested oil was light (approximately 30 o API) and sweet with a low gas-oil ratio and some associated wax. Flow data from the test indicated that the reservoir had an extremely high permeability of over 2,000 millidarcies. Three intervals were successfully tested in February 2007, from between 2,260 metres to 2,367 metres and produced a cumulative flow rate of 9,773 bopd over a total net productive thickness of 44 metres. The oil is of good, quality light (between 30 o and 32 o API) and sweet with a low gas-oil ratio and some associated wax. The reservoirs are sandstones with high permeability up to 3,000 millidarcies. 3D and 2D seismic programmes have identified a number of targets in Blocks 3A and 1, for which multi-well drilling programmes are planned to commence in the first half of A 325 square km 3D seismic survey was carried out over the Kingfisher and neighbouring Pelican structures during the summer of Initial interpretation of the 3D seismic survey confirms that the Kingfisher structure has an aerial extent of approximately 45 square km. The data also identifies a number of appraisal/development targets within the Kingfisher structure for a multi-well drilling programme from land and on Lake Albert. A 530 km 2D seismic acquisition programme was completed in Block 3A in Lake Albert in the third quarter of This most recent programme supplemented previously acquired 2D seismic surveys and covered previously un-surveyed areas of Lake Albert, in order to identify additional drilling targets. 43

46 The Kingfisher appraisal drilling programme is scheduled to commence in the first half of 2008, following the release of the Nabors 221 rig from neighbouring Block 2. Management expects this land rig to have the capability to reach the depth of the primary target horizon not reached by previous Kingfisher drilling. The previous Kingfisher-1 well produced approximately 13,900 bopd from shallower, secondary target horizons. Drilling of the Pelican prospect and other prospects in the lake identified by recent seismic programmes is planned to commence in the first quarter of Expression of interest documents to obtain a barge mounted rig have been issued recently. A 2D seismic survey has been carried out on in Block 1, where relatively shallow structures have been identified with associated amplitude anomalies. Oil is known to have migrated into Block 1, as evidenced by the active oil seep within the block located at Paraa. This oil seep together with the presence of amplitude anomalies, further supports the potential presence of hydrocarbons within the block. The drilling programme in Block 1 has been accelerated following drilling results in neighbouring licences, as well as the results from the current seismic programme. Management expects an exploration drilling programme to commence in or after the summer of 2008, concentrated on the shallower targets in the southern part of the block. A mobile rig has recently been contracted by the operator of the neighbouring licence which will be used for this drilling programme rig. Capital expenditures in Uganda between 2005 and 2007 under (IFRS) may be summarised as follows: Nine-month periods ended Year ended 31 December 30 September $ $ $ $ (Unaudited) Drilling... 2,466,385 11,999,638 5,327,637 7,814,808 Seismic... 1,059,395 12,720,495 Other... 2,123,457 1,665,298 1,171,610 1,543,342 5,649,237 13,664,936 6,499,247 22,078,645 Independent Resources at Block 3A and 1 RPS estimated that the gross risked recoverable contingent and prospective resources in Blocks 3A and 1 are as follows: Gross Risked Recoverable Resources (MMstb) p90 p50 p10 Mean , The Group has a 50 per cent. working interest. The Government of Uganda has a back-in right which could, if exercised, reduce the Group s working interest to 42.5 per cent. Democratic Republic of Congo The DRC is located in West and Central Africa. Oil production is located in the western part of the country from the restricted Atlantic offshore and adjacent coastal onshore Congo Basin. The Group s interests cover the entire area of Lake Albert that lies within the DRC, plus a smaller area onshore to the south of the lake adjacent to the Semliki flats in Uganda. Blocks 1 and 2, adjacent to the Ugandan blocks, in the DRC are held under a single PSC with the government of DRC, which was signed in July The Group holds a 39.5 per cent. interest in both blocks, with Tullow, the operator, holding 48.5 per cent. and the DRC state oil company, COHYDRO, holding the remaining 12 per cent. The initial exploration term is five years, during which seismic data will be acquired and exploration wells drilled. However, such works will only commence following the receipt of a presidential decree, the timing of which is uncertain. The Group has agreed to a total minimum contractual work programme which includes collecting and reanalysing existing seismic data, conducting one 400 km and two 200 km seismic surveys, and drilling four 44

47 exploration wells. The total estimated gross financial commitment amounts to $18.6 million spread over the five year exploration period. Given the proximity of the DRC licences to the Uganda licences in the Albert Basin, there should be cost benefits from sharing certain operating, capital and infrastructure development costs, including the development and construction of a potential international export pipeline to Mombasa on the east coast of Kenya. Map of Blocks I and II and Surrounding Area 22MAR Iraq and the Kurdistan Region of Iraq Iraq has the second largest light oil reserves in the world, estimated at 112 billion bbls of oil and 100 trillion cubic feet of gas (as stated in the CIA World Factbook as at 1 January 2006). The KRI is an underexplored area with potential resources. The area has had political stability and has relatively low security risk compared to other areas of Iraq. 45

48 Map of Miran Block and Surrounding Area 44º0 0 E 45º0 0 E 46º0 0 E IRAN Demir Dagh MIRAN 36º0 0 N Taq Taq 36º0 0 N Ismail 1 Kirkuk Bai Hassan Khabbaz Kirkuk Chemchemal Suleimaniah IRAQI KURDISTAN Jambur Kor Mor 35º0 0 N Ajeel Judaida º0 0 N 50km Hamrin Pulkhana LEGEND Gilabat 1 Qamar Chia Surkh 2 Oil Fields Gas Fields Injana 5 Gas Condensate Field Prospect IRAQ Heritage PSA 44º0 0 E 45º0 0 E 46º0 0 E 14MAR The Group was one of the first companies to be awarded a PSC in the KRI. Heritage Middle East, a wholly-owned subsidiary of the Company executed a PSC with the KRG over the Miran Block in the KRI on 2 October The Group has been appointed operator. The licence area covers approximately 1,015 square km. The Miran structure itself is in excess of 500 square km in area and the possibility exists for multiple reservoir targets. It is estimated by the Directors that the structure could contain significant quantities of oil. The Miran structure lies only 55 km from the giant Kirkuk oilfield with remaining reserves thought to be in excess of 10 billion bbls and 30 km from the Taq Taq field on which recent wells have tested degree API oil at flow rates of between 15,000 and 37,000 bopd on production test. The Group received a letter from the Iraq Ministry of Oil dated 17 December 2007 stating that the PSC signed with the KRG (without the prior approval of the Iraqi government) is considered to be void by the Iraqi government as they have stated it violates the prevailing Iraqi law. On the basis of KRI legal advice, the Directors believe that the PSC is valid and effective pursuant to the applicable laws. 46

49 The Group has also entered into a separate strategic agreement with the KRG to establish a 50/50 joint venture company which shall build, own and operate an oil refinery in the vicinity of the block. The refinery, which should have a capacity of 20,000 bopd, is scheduled to be operational to design specification within approximately two years of the signing of the agreement. Mali The Group is the operator and has the right to earn a 75 per cent. working interest in each of Blocks 7 and 11 by financing 100 per cent. of the minimum work programme over the next two years. The blocks cover a gross area of over 72,000 square km and are located in the Gao Basin. The Group s partner is Mali Oil Developments SARL a wholly-owned subsidiary of Centric Energy Corporation. In return for acquiring the working interest, the Group has agreed to fund the costs of the required work programmes estimated to be a minimum of between $14 and $15 million in order to earn its 75 per cent. working interest. Block 7 exploration period can be renewed twice for a duration of 3 years for each period subject to additional spend commitments of $8 million for the first and $14 million for the second renewal period. Block 11 exploration period can be renewed twice for a duration of 3 years for each period subject to additional spend commitments of $8 million for the first and $15 million for the second renewal period. Map of Blocks 7 and 11 and Surrounding Area 14º 12º 10º 24º 8º 6º 4º 2º 0º 20º 4º 6º 24º LEGEND 22º Heritage PSA Exploration Well Well & Gas Shows MALI ALGERIA 22º International Border Atouila-1 20º km 20º m Yarba-1 Block 7 Kidal In Tamat-1 18º 18º 16º MAURITANIA Timbuktu Tin Bergoui-1 Gao Block 11 Ansongo-1 Tahabanat-1 16º SENEGAL 14º 12º Kayes GUINEA 10º 14º 12º 10º Mopti Sègou Koulikoro Bamako Sikasso IVORY COAST 8º 6º 4º 2º BURKINA FASO Ouagadougou GHANA TOG NIGER 14º Niamey BENIN 0º 2º 4º 12º NIGERIA 10º 14MAR The two licences are located in the Gao Basin, a Mesozoic basin that the Directors consider has geological similarities to other Mesozoic interior-rift basins within North Africa, such as the Muglad Basin of Sudan and the Doba Basin of Chad, and Tertiary basins such as the Albert Basin of Uganda. Previous seismic data acquired in Blocks 7 and 11 show the presence of tilted fault-block traps, and indicate up to approximately 4 km of sediments in the geological section. Malta On 14 December 2007, the Group entered into a PSC with the Maltese Government for a 100 per cent. interest in Blocks 2 and 7 in the south-eastern offshore region of Malta. The Group is the operator. The licences (Blocks 2 and 7) extend to almost 18,000 square km and are situated approximately 80 km (in the case of Block 2) and 140 km (in the case of Block 7) from the south-eastern Maltese coastal waters in 47

50 depths of approximately 300 metres. Initial seismic interpretation, based on the current extensive data set of almost 3,500 km acquired after 2000, has identified a variety of potential prospects. Primary targets are Lower Eocene and Cretaceous carbonates that are recognised to be major hydrocarbon producing plays in the central part of the Mediterranean. The licences are under-explored, having had only one well drilled in Block 2 (Medina Bank 1) in The well was drilled to a depth of 1,225 metres and failed to reach the target horizons estimated to be at 1,500 to 4,500 metres. It did, however, encounter gas shows in porous, fractured carbonates. The Group received a letter from the chairman of the Management Committee of the National Oil Corporation of Libya dated 28 February 2008 stating that the Block 7 licence area lies within the Libyan continental shelf and a portion of this area has already been licensed to Sirte Oil Company. This letter also demands that the Group refrain from any activities over or concerning the Block 7 licence area and asserts the Libyan government s right to invoke Libyan and international law to protect its rights in the Block 7 licence area. The Directors believe that the Libyan government s claims are unfounded. The Group has agreed to a total minimum contractual work programme comprising the acquisition of a further 1,000 km of seismic data and the drilling of one exploration well. The total minimum financial commitment amounts to $22 million spread over the first three year exploration phase which may then be extended for a further three year period thereafter. Map of Blocks 2 and 7 and Surrounding Area SICILY Siracusa (Syracuse) Tunis MS-B1 Valetta 1 TUNISIA Sfax Lampuko 1 Gozo 1 Madonna Taz-Zejt 1ST1 Naxxar 2 MALTA Valetta Aqualta 1 Tama 1 Alexia 1 Alexia 2 MS-A1 Malta 1 Medina Bank 1 Block 2 Block 7 Area of seismic coverage LEGEND Block boundary Area of seismic coverage Exploration Well Oil & Gas shows International Border Tarãbulus (Tripoli) A-001-NC146 A-001A-NC087 B-001-NC km 0 50m 25 LIBYA 14MAR Pakistan A wholly-owned subsidiary of the Company was awarded a 60 per cent. participating interest in the Sanjawi Block (number ) in Zone II (Baluchistan), Pakistan. The onshore exploration licence has a gross area of 2,258 square km. The exploration licence and PSC were executed on 16 November 2007 and the Group has been appointed operator. There are two Pakistan-based joint venture partners pursuant to the PSC, Sprint Energy (Pvt) Limited (being a subsidiary of the JS Group, a Pakistan-based financial services provider), and Trakker Energy (Pvt) Limited. 48

51 Pakistan has current proved hydrocarbon reserves of approximately 289 million bbls and 765 billion m 3 gas (as stated in the CIA World Factbook, 2006 estimate), mainly situated in the central and southern parts of the Indus Valley, with current production of approximately 68,000 bopd and approximately 3.9 million m 3 /day gas (as stated in the CIA World Factbook, 2006 estimate), all of which is consumed domestically. An additional 279,000 bopd are imported (as stated in the CIA World Factbook, 2004 estimate). Map of Sanjawi Block (number ) and Surrounding Area 64º UZBEKISTAN Dushanbe 72º LEGEND TAJIKISTAN CHINA Heritage PSA Oil Fields Gas Fields Gas Condensate Field AFGHANISTAN International Border Gas pipeline Oil pipeline Kabul Peshawar Islamabad Refined product pipeline 32º km m PAKISTAN Lahore Savi Ragha-1 Dhodak 32º Khattan Quetta Sanjawi Salsabil Miriwah -1 Zarghuri South-1 Khattan Jandran -1 Indus New Delhi IRAN INDIA Karachi 24º 24º 64º 72º 14MAR MANAGEMENT AND EMPLOYEES Employees As of 31 December 2007, the Group had 6 directors and 87 employees and consultants. The Group s management has experience in international production and exploration and has the capability to expand the scope of the Group s activities as opportunities arise. Management selects value- 49

52 enhancing opportunities and may form strategic alliances with influential local partners in its chosen regions to deliver growth in shareholder value. The Group leverages off a highly effective network of influential industry, political and institutional relationships. These relationships enable the Group to form strategic alliances which reduce resource commitments and lower exploration and development risk, as well as give the Company access to properties. The Group s management team has demonstrated its ability to make substantial oil discoveries and its flat and lean structure has enabled the Group to enjoy first-mover advantage in many of its deals and to take advantage of interesting opportunities, such as the KRI and the Albert Basin in Uganda. 8. SAFETY, ENVIRONMENT, RISK MANAGEMENT AND CORPORATE AND SOCIAL RESPONSIBILITY Corporate and Social Responsibility The Group has always been committed to responsible and respectful conduct towards the diverse communities in which it operates, believing that it is only through such an approach to business incorporating economic, environmental and social initiatives that the Group s sustainable development will be achieved. The Group believes that in order to create long-term value for its stakeholders, partners and employees, it is imperative that it contributes to its adopted communities. Investing in local communities today is increasingly accepted as a necessary part of doing business, especially in developing economies that lack basic infrastructures and the capacity to build social capital as this contributes to a healthy and stable business climate. Over the past five years the Group has implemented a wide range of community projects comprising public health, education, environmental, public facility, and community relations-based programmes. In all of these, the Group s involvement was not simply to provide funds, but to actively work with the communities in order to build trust and ensure that both the needs of communities and those of the Group were considered when the projects were planned. For example, in Uganda the Group has worked closely with local communities in Rwebisengo-Bundibugyo District and Buhuka-Hoima District, to build and rehabilitate roads and valley dams, drill community water wells and construct cattle dipping tanks. The Group has constructed and repaired fencing around a number of schools such as Makondo Primary School in the Bundibugyo District and invested in schools uniforms, sportswear and equipment. The Group s values encompass a continuous dedication to education, learning and training. To this end the Group tailors a number of its corporate and social responsibility initiatives to be specifically educationoriented, such as examples in Uganda where the Group is building a school and teachers residences at Buhuka and the establishment of a Petroleum Institute for higher education collectively with other oil companies operating in Uganda. The Group has so far sponsored three undergraduate students for courses at universities in Kampala, Uganda; one comes from Bundibugyo district and two from Hoima District. The Group has also trained over 65 officials from the oil ministries in Iraq and the KRI. Approximately 20 per cent. of the Group s corporate and social responsibility expenditure is deployed in nature conservation projects. In Uganda, the Group s employees are involved in a wide variety of fieldbased projects including sponsorship of wildlife conservation and investment in transportation by providing four-wheel drive vehicles and motorcycles for game wardens. From the outset of these programmes, the Group has actively engaged each community and their local government in planning and agreeing the project implementation strategies and timings (the communities are involved at the onset of the project so that they have a sense of ownership and are able to continue implementation of the project on a sustainable basis). Protecting the environment The Group is committed to protecting the environment and for every project envisaged having an impact on the environment; an Environmental Impact Assessment is usually conducted, where potential impacts are identified and appropriate mitigation measures are put in place. The mitigation measures are made 50

53 operational by drawing up an Environmental Management Plan, and this is followed by monitoring the effectiveness of the plans employed to protect the environment or allow its self-renewal. Environmental Incidents The Group attaches great responsibility to its emergency response plans which are instituted in case of any environmental incidents. The Directors place considerable confidence in the effectiveness of the Group s environmental incident reporting procedures. To date, the Group has not been subject to any material environmental incidents. 9. HISTORY AND DEVELOPMENT The Group was formed in 1992 and HOC was incorporated in Over the past twelve years, the Group has grown through its strategy of focusing on high-impact international opportunities containing multiple targets with the potential for the discovery of significant reserves, achieved through the management of technical and political risk, through the geographic spread of licences and the experienced management team s hands-on approach. Relationship with Mr. Anthony Buckingham Anthony Leslie Rowland Buckingham is a citizen of the United Kingdom, born on 28 November 1951 in London, England. In 1972, Mr. Buckingham commenced work in the oil industry as an international saturation diver. In 1979, he became a lecturer at Seneca College, Ontario, Canada. Mr. Buckingham then held senior positions in various diving and engineering companies, including being appointed as the Operations Manager, New Ventures Secretariat (a think tank) at British Oxygen Company (now part of the Linde Group), before becoming a concession negotiator in the 1980s acting for Ranger and Premier Oil plc. During this time he lived in Karachi and Quetta (the capital of the province of Baluchistan) in Pakistan. In 1989, he became an adviser to the Government of Angola and assisted the Angolan Oil Ministry in establishing Sonangol P&P as an active oil and gas exploration and production company. Mr. Buckingham founded HOC which was incorporated in the Bahamas on 14 January 1992 as Land and Marine Hydrocarbons Development Limited. The name was changed to Heritage Oil & Gas Limited on 10 June HOC was initially formed to hold certain oil and gas exploration interests in offshore Angola, principally an interest in a PSC in respect of Block 4 in the Lower Congo Basin, and through ROWAL a joint venture company with Ranger, a reversionary interest in the Kiabo oil field owned and operated by the Angola state oil company, Sonangol. ROWAL was owned 51 per cent. by Ranger and 49 per cent. by HOC. Heritage s activities were initially funded by share and loan capital provided by Fleming Mercantile Investment Trust plc and Premier Oilfields plc in ROWAL provided certain technical and advisory services to a division of Sonangol to assist Sonangol in the financing, development and operation of the Kiabo oilfield on sub-block 4/26, in return for a reversionary 10 per cent. net profits interest in the Kiabo field. The agreement and services were terminated in ROWAL was forced to abandon certain oil field and drilling equipment at its base at Soyo in northwestern Angola after it was overrun by UNITA rebels who killed a number of locals and expatriates in ROWAL engaged the services of Executive Outcomes, a private military company, which successfully retrieved the equipment, allowing the exploration work programme to continue. The loan finance to Fleming was thereafter repaid. In 1996, Ranger and HOC amended the existing arrangements so that HOC received a 5 per cent. net profits interest in the Kiame development and a 2 per cent. net profits interest in the balance of Block 4 (other than sub-blocks 4/26 and 4/24 containing the Kiabo oilfield and another undeveloped discovery which predated the award of Block 4 to Ranger). 51

54 The Kiame oilfield, offshore Angola operated by Ranger, commenced production in June Production from the field terminated in April Heritage held a 5 per cent. net profit interest. Angola is reportedly the second largest oil producing country in Africa, producing an average of over 1.4 million bbl/d of oil. Association with private military contractors In 1993, ROWAL was forced to abandon certain oil field and drilling equipment at Soyo in north-western Angola, after it was overrun by UNITA rebels who killed a number of locals and expatriates. As a direct result of this loss, Mr. Buckingham together with Eeben Barlow, Lafras Luitingh and Simon Mann became business partners in Executive Outcomes, a private military company, formed by Mr. Barlow in Executive Outcomes senior personnel were composed primarily of former members of the South African Defence Force and special forces, and the company successfully recovered the equipment ROWAL had been forced to abandon. Following the success of the operation at Soyo, the internationally recognised government of Angola engaged Executive Outcomes in a contract to re-train certain elements of the Angolan army and support it in defeating the UNITA rebels. The contract with the Government of Angola terminated in In 1995, the government of Sierra Leone engaged Executive Outcomes to train the Sierra Leone army and support it in defeating the RUF rebels, who were intent on overthrowing the government. The joint co-operation achieved a level of success sufficient to witness the signing of a peace accord and democratic elections held in The contract was terminated with effect from January 1997 prior to regional stability forces entering the country. The operations in Angola and Sierra Leone were Executive Outcomes largest and most significant contracts. The company was dissolved on 1 January Sandline International was formed in late 1996 with Mr. Buckingham as one of the principals and Lieutenant Colonel (Retired) Tim Spicer OBE appointed as Chief Executive. Sandline International was engaged by the internationally recognised government of PNG, led by Prime Minister Julius Chan, in 1997, to support its continued efforts against the BRA who were seeking independence from PNG. Following an uprising led by the PNG army by Brigadier Jerry Singirok, operations were terminated and Mr. Spicer was temporarily detained by an element of the army who were not in agreement with the government s plan of how to conclude the BRA s insurgency. The government of PNG settled in full with Sandline International following an international arbitration which unanimously found in Sandline International s favour and confirmed that a valid contract had been in existence. In 1998, Sandline International was engaged to support the ECOMOG, a West African multilateral armed force established by the ECOWAS, in its operations in Sierra Leone. ECOMOG, led by Nigerian forces, was employed to oust rebels who had taken control of Sierra Leone s capital, Freetown and other large areas of the country, leaving the democratically elected government to flee into exile. Sandline International provided support and assistance to ECOMOG, undertook humanitarian rescues and supplied certain equipment to them. As reported in the Sir Thomas Legg s Report published in July 1998, operations were carried out with the tacit approval of Her Majesty s Government as well as support from a Royal Navy frigate. The operations in Sierra Leone ceased in the spring of 1998, Sandline International became dormant and the company was dissolved in Termination of Association with private military contractors Following the cessation of operations and subsequent dissolution of each of Executive Outcomes and Sandline International, there has been no association with any private military contractors. It is reported that Simon Mann is now incarcerated in Black Beach jail in Equatorial Guinea, for the failed plot to overthrow President Teodoro Obiang of Equatorial Guinea. Mr. Buckingham has had no substantive business contact with Simon Mann since 1998 and no contact of any nature with him since He had no involvement with or knowledge of Mr. Mann s activity in Equatorial Guinea. Lieutenant Colonel (Retired) Tim Spicer OBE subsequently founded and became the Chief Executive Officer of Aegis in Aegis reportedly is a privately owned British security and risk management company with overseas offices in Afghanistan, Bahrain, Iraq, Kenya, Nepal and the United States of America and provides services to various governments including the United States of America, is security advisor to the Lloyds Joint War Risk Committee and is an active United Nations contractor. 52

55 Mr. Buckingham has never had any association with Aegis and has had no involvement with any military or security operations since the spring of Corporate Development The Company is a newly-formed company incorporated in Jersey. The purpose of the Company is to invest indirectly (via its indirectly wholly owned subsidiary DutchCo) in the entire issued share capital of HOC. It is assumed that immediately subsequent to and assuming the completion of the Plan of Arrangement (which is conditional upon Admission), DutchCo will indirectly hold 100 per cent. of the total issued and outstanding HOC Common Shares. The registered office of the Company is located at Ordnance House, 31 Pier Road, St Helier, Jersey JE4 8PW, Channel Islands and its head office will be at The Parade, St Helier, Jersey, JE1 1BG Channel Islands. Chronology of Key Events The table below sets out certain significant milestones in the recent history of the Group. Date Event The Group was founded. HOGL was incorporated in the Bahamas on 14 January 1992 as Land and Marine Hydrocarbons Development Limited, which name was changed to Heritage Oil & Gas Limited on 10 June The Group was initially formed to hold certain oil and gas exploration interests in offshore Angola, principally an interest in a PSA in respect of Block 4 in the Lower Congo Basin, and through ROWAL a joint venture company with Ranger, a reversionary interest in the Kiabo oil field owned and operated by the Angola state oil company, Sonagol. ROWAL was owned 51 per cent. by Ranger and 49 per cent. by the Group. ROWAL provided certain technical and advisory services to a division of Sonangol to assist Sonangol in the financing, development and operation of the Kiabo oilfield on sub-block 4/26, in return for a reversionary 10 per cent. net profits interest in the Kiabo field. The agreement and services were terminated in The Group s activities were initially funded by share and loan capital provided by Fleming and Premier Oilfields plc ROWAL was forced to abandon certain oil field and drilling equipment at its base at Soyo in north-western Angola after it was overrun by UNITA rebels who killed a number of locals and expatriates. ROWAL engaged the services of Executive Outcomes, a private military company, which successfully retrieved the equipment, allowing the exploration work programme to continue The Group received a 2.5 per cent. commission amounting to approximately $2 million relating to the construction of two production platforms in South Africa for use in the Cabinda region, offshore Angola Ranger and the Group amended the existing arrangements so that the Group received a 5 per cent. net profits interest in the Kiame development and a 2 per cent. net profits interest in the balance of Block 4 (other than sub-blocks 4/26 and 4/24 containing the Kiabo oilfield and another undeveloped discovery which predates the award of Block 4 to Ranger) The Group acquired a 10 per cent. interest in Block 8, offshore Oman. This licence contains the West Bukha field The Group was awarded a 50 per cent. interest and operatorship of the Kouilou exploration licence and Kouakouala A, B, C and D licences onshore Congo The Group was awarded a 100 per cent. interest and operatorship of Block 3 and subsequently drilled three test wells at the same Turaco drill site, Uganda 53

56 Date The Kiame oilfield, offshore Angola, operated by Ranger, commenced production in June Production from the field terminated in April The Group held a 5 per cent. net profit interest HOC listed the HOC Common Shares on the TSX Maurel et Prom farms into the Kouilou and Kouakouala A, B, C and D licences in the Congo and is appointed operator. The Group s working interest reduces to 25 per cent. of Kouakouala A permit and 30 per cent. of the Kouilou exploration licence and Kouakouala B, C and D licences The Group sold a 50 per cent. working interest in the Uganda Block 3 licence to Energy Africa Discovery of the M Boundi field in the Kouilou exploration permit The disposal of the Group s 30 per cent. working interest in the Kouilou permit in the Congo in the first half of 2002 to Maurel & Prom for a consideration of $30 million in cash, $5 million in interest bearing convertible debentures in the purchaser and the retention of a 5 per cent. gross override royalty that becomes effective after 67 million bbls have been produced The disposal of the M Boundi royalty to Maurel et Prom for proceeds of $30.4 million. Acquisition of a 7 per cent. working interest in the Noumbi exploration permit in the Congo for $7 million The Group is awarded a 50 per cent. working interest in Blocks 1 & 3A in Uganda and is appointed operator The Group acquired a 95 per cent. interest in the Zapadno Chumpasskoye field, in Russia and appointed as operator. 2006/07... On 27 March 2006, HOC issued 600 unsecured convertible bonds each with a par value of $100,000 for aggregate proceeds of $60 million. The bonds had a coupon rate of 10 per cent. per annum and a term of five years and one day. At the option of the holders, the bonds were convertible, in whole or in part, into HOC Common Shares at a price of U.S.$18.00 per share at any time during the term of the bonds. HOC had an option to redeem, in whole or part, the bonds for cash at any time on or before 28 March 2007, at 150 per cent. of par value. On 17 January 2007, HOC gave notice that it had exercised its option to redeem the 550 outstanding unsecured convertible bonds at 150 per cent. of par value for total proceeds of $82.5 million plus accrued interest which was paid on 28 March Fifty of the 600 unsecured convertible bonds, with a total par value of $5 million, were converted into 277,778 HOC Common Shares at an exercise price of $18.00 per share subsequent to 31 December In July 2006, Blocks 1 and 2, adjacent to the Ugandan blocks, in the DRC were awarded under a single PSC with the government of the DRC The Group entered into an agreement with TISE Holding Company to establish a jointly owned company, TISE-Heritage Nefetegas, which was incorporated in 2007 to appraise and jointly acquire oil and gas opportunities in Russia and internationally. Shareholders of TISE Holding Company include Concord, Zarubejneft, Zarubejneftegas (a wholly-owned Gazprom subsidiary), Technopromexport and Zarubejstroymontaj In November 2006, Heritage Congo was sold to Afren for a consideration of $21.0 million, plus 1,500,000 Afren warrants, with a term of five years and an exercise price of 0.60 per share. Heritage Congo held a 14 per cent. interest in the Noumbi Permit, in the Congo At the end of 2006, the West Bukha-2 appraisal/development well test produced a combined flow-rate from the zones tested (Ilam/Mishrif/Mauddud and Thamama) of approximately 12,750 bopd and 26 MMscf/d. Event 54

57 Date On 18 January 2007, the Group finalised the statement of adjustments relating to the sale of its 25 per cent. working interest in the Kouakouala A licence and 30 per cent. working interest in the Kouakouala B licence in the Congo to the other partners in the licences, Maurel et Prom and Burren Energy, for the following consideration: cash of $6,052,515, which has been received; and an overriding royalty of 15 per cent. over a 30 per cent. working interest in the Kouakouala B licence in relation to the Mengo field. The Mengo field is not currently in production On 16 February 2007, HOC raised $165 million by completing a private placement of convertible bonds. HOC issued 1,650 unsecured convertible bonds, at par, which have a maturity of five years and one day and an annual coupon of 8 per cent. paid semi-annually. The bonds are convertible into HOC Common Shares at a price of $47 per share. HOC had the right to redeem, in whole or part, the bonds for cash at any time on or before 16 February 2008, at 150 per cent. of par value. HOC did not exercise this right First production from the Zapadno Chumpasskoye field in Russia commenced on 14 May The Kingfisher deviated well in Block 3A in Uganda was drilled to a total depth of 3,195 metres. Drilling was completed in March Four intervals were tested successfully in the Kingfisher well, resulting in an overall cumulative maximum flow rate of 13,893 bopd. The oil is good quality light (between 30 o and 32 o API) and sweet with a low gas-oil ratio and some associated wax In October 2007, the Group executed a PSC with the KRG over the Miran Block in the south-west of the KRI. The Group also agreed to be a 50/50 partner with the KRG to design and build a 20,000 bopd oil refinery in the vicinity of the licence area. Heritage Middle East has been appointed as Operator The Group farmed-in to two onshore exploration licences in the Republic of Mali, in North-West Africa, with a gross area of over 72,000 square km in November The Group has been appointed as Operator. The Group entered into farm-in agreements which contain the right to earn a 75 per cent. working interest in Block 7 and Block 11 from Centric Energy Corporation On 14 November 2007, HOC completed an equity financing, raising gross proceeds of Cdn $181.5 million from the issue of 3,000,000 HOC Common Shares. As part of the same transaction, the Major Shareholder sold 3,000,000 HOC Common Shares reducing its interest from 52 per cent. to 32 per cent On 16 November 2007, the Group was awarded an onshore exploration licence in Pakistan, with a gross area of 2,258 square km. The Group has been awarded a 60 per cent. participating interest in the Sanjawi Block (No, ) in Zone II (Baluchistan) and appointed as operator In December 2007, the Group was awarded 100 per cent. of Areas 2 & 7 offshore Malta A court approved reorganisation of the share capital of HOC by plan of arrangement is proposed for completion on or about 31 March 2008 pursuant to the ABCA. For further detail, refer to Part VIII of this document. Event 10. REASONS FOR THE PLAN OF ARRANGEMENT AND LONDON LISTING The Directors believe that the reorganisation of the Group, in a tax efficient manner, in accordance with the terms of the Arrangement Agreement and the admission of the Ordinary Shares to the Official List and to trading on the main market of the LSE is in the best interests of the Group and holders of securities in HOC. Given the geographic spread of the Group s production, development and exploration licences with a core focus on Africa, the Middle East and Russia, the Directors believe that it would now be more appropriate for the Group to be based in Europe, where a substantial number of holders of securities in HOC and most of the management of the Group reside. 55

58 The Directors believe that admission to the main market of the LSE will raise the Group s profile and status amongst European investors and within the oil and gas sector generally, and will give the Company access to an international market with a broad, relevant peer group and considerable research expertise. Furthermore, the Directors believe that in due course a listing on the main market in London should assist in increasing the trading and liquidity of the Ordinary Shares and Exchangeable Shares. The HOC Common Shares will be de-listed from the TSX approximately two business days (being business days in London, England and Toronto, Canada) after the effective date of the Plan of Arrangement. However, in order to give Canadian-resident shareholders in HOC a tax efficient method of participating in the Plan of Arrangement such shareholders have been offered Exchangeable Shares of HOC as an alternative to exchanging their HOC Common Shares for Ordinary Shares on the effective date of the Plan of Arrangement. The TSX has conditionally approved the listing of the Exchangeable Shares on the TSX subject to the receipt of final documentation. Each HOC Common Share will be exchanged for either ten Ordinary Shares or ten Exchangeable Shares, as part of the Plan of Arrangement in order to increase the liquidity, following Admission, of the Ordinary Shares and the Exchangeable Shares in addition to providing a suitable initial trading price for Ordinary Shares on the LSE. At a future date after 12 months from the date of this document, in order to finance the remainder of the operation expenditures required to bring the initiated oil and gas exploration activities of the Group into full production the Group is likely to require additional equity and/or debt financing or the sale of noncore assets. For the purpose of the Illustrative Projections of the Group (contained in Part VIII of this document) this additional funding is assumed to be equity finance. 11. INTERCORPORATE RELATIONSHIPS The corporate structure of the Group, on implementation of the Plan of Arrangement, its principal active subsidiaries and the other entities in which the Group holds a material interest, the percentage ownership of voting securities in such subsidiaries or other entities and the jurisdiction of incorporation of such subsidiaries or other entities is set out in the structure chart below (for more detail on the companies set out below, please refer to Part X Additional Information ). Heritage Oil Limited (Jersey) 100% (1) Heritage Oil Corporation (Alberta) 100% (2)(3) Heritage Oil & Gas Ltd. (Bahamas) 100% 100% 100% 100% 99% Heritage Oil International Malta Ltd. (BVI) Heritage Energy Holding GesmbH (Austria) Coatbridge Estates Ltd. (BVI) (6) Eagle Energy (Oman) Ltd. (Isle of Man) (5) Neftynanaya Geologiches kaya Kompaniya (Russia) 100% 100% 100% 100% 50% Heritage Oil & Gas (U) Ltd. (Uganda) (4) Heritage DRC Limited (Nevis) Heritage Energy Middle East Ltd. (Nevis) Heritage Mali Block 7 (Nevis) Heritage Mali Block 11 (Nevis) 50% 95% TISE- Heritage Neftegaz (Russia) Chumpass NefteDoby cha (Russia) 17MAR Notes: (1) This holding represents the one hundred per cent indirect holding of HOC Common Shares only. (2) This holding represents an indirect one hundred per cent holding via Heritage (Barbados) and then Heritage Holdings. 56

59 (3) One common share of Heritage Holdings is held by Hansard Trust Company Limited with a Declaration of Trust in favour of Heritage Holdings. (4) One common share of Heritage Oil & Gas (U) Ltd. is held by Hansard Trust Company Limited with a Declaration of Trust in favour of Heritage Holdings Limited. (5) One common share of Eagle Energy (Oman) Ltd. is held by Hansard Trust Company Limited with a Declaration of Trust in favour of HOGL. (6) One common share of Coatbridge Estates Limited is held by Hansard Trust Company Limited with a Declaration of Trust in favour of HOGL. 12. EFFECT OF JERSEY DOMICILE The City Code The City Code will apply to the Company, as it applies to companies that have their registered office in the United Kingdom, the Channel Islands or the Isle of Man if any of their securities are admitted to trading on a regulated market in the United Kingdom or any stock exchange in the Channel Islands or the Isle of Man. Accordingly, upon Admission, shareholders of the Company will be afforded the protections provided by the City Code, in particular the mandatory takeover provisions in rule 9 of the City Code. In the event of a takeover, the squeeze-out provisions in articles 117 to 119 of the Act would be available subject to, amongst other things, the offeror acquiring the requisite percentage of the share capital to which the offer relates. Company Law There are a number of material differences between the Companies Act and the Act which may impact upon the rights of holders of Ordinary Shares or the Exchangeable Shares. The salient differences are set out in more detail in Part X Additional Information of this document. However, the Company, through its Articles, has adopted many provisions commonly found in the Companies Act and the New Companies Act. For example, rights of pre-emption broadly similar to those contained in the New Companies Act have been adopted in the Company s Articles. Details of these Articles are set out in more detail in section 6.2(e) of Part X of this document. 13. ADMISSION AND SETTLEMENT Application has been made to the FSA for all of the Ordinary and Exchangeable Shares to be admitted to listing on the Official List and to the LSE for such Ordinary and Exchangeable Shares to be admitted to trading on its main market for listed securities. It is expected that Admission will become effective and that dealings in the Ordinary Shares will commence by no later than 8.00 a.m. on 31 March 2008 and the Exchangeable Shares will commence no later than 8.00 a.m. on 2 April Applications have been made for the Ordinary Shares to be admitted to CREST. CRESTCo requires the Company to confirm to it that certain conditions imposed by the Regulations are satisfied before CRESTCo will admit any security to CREST. It is expected that these conditions will be satisfied in respect of the Ordinary Shares on admission of the Ordinary Shares to the Official List. As soon as practicable after satisfaction of the conditions, the Company will confirm this to CRESTCo. Securities issued by non-uk registered companies, such as HOC in respect of the Exchangeable Shares, cannot be held or transferred in the CREST system. However, to enable investors to settle such securities through CREST, a depositary or custodian can hold the relevant securities and issue dematerialised depositary interests representing the underlying securities which are held on trust for the holders of the depositary interests. As at the date of this document, the directors of HOC are in the process of finalising a depositary interest arrangement with Computershare to facilitate the transfer of Exchangeable Shares between Canada and the UK. Although at Admission the depositary interest arrangement will not yet be in place, it is expected that such arrangement will be implemented shortly after Admission. 57

60 PART II DIRECTORS, MANAGEMENT AND CORPORATE GOVERNANCE 1. DIRECTORS AND SENIOR MANAGEMENT Directors Name Position Term Michael Hibberd... Chairman and Non-Executive Director 2 years, then 3 years Anthony Buckingham... Chief Executive Officer 2 years Paul Atherton... Chief Financial Officer 2 years Gregory Turnbull... Non-Executive Director 1 year, then 3 years John McLeod... Non-Executive Director 1 year, then 3 years General Sir Michael Wilkes... Non-Executive Director 3 years, then 3 years (a) Michael Hibberd Mr. Hibberd has extensive international energy project planning and capital markets experience. Mr. Hibberd has been President and CEO of MJH Services Inc., a corporate finance advisory company since 1995, prior to which he spent 12 years with Scotia McLeod in corporate finance and held the position of Director and Senior Vice-President, Corporate Finance. He is also Chairman and co-ceo of Sunshine Oilsands Ltd. and currently serves on the boards of directors of AltaCanada Energy Corp., Challenger Energy Corp., Iteration Energy Ltd., Pan Orient Energy Corp., Ramtelecom Inc. and Zapata Energy Corporation. Mr. Hibberd also served as a director of Rally Energy Corp. until October 2007 and as a director of Deer Creek Energy Limited until December Mr. Hibberd joined HOC in March (b) Anthony Buckingham Mr. Buckingham is the founder of the Group. Mr. Buckingham commenced his involvement in the oil industry as a North Sea diver and subsequently became a concession negotiator acting for several companies including Ranger Oil Limited and Premier Oil plc. He was previously a security adviser to various governments. Further information on Mr. Buckingham is set out in History and Development in section 9 of Part I of this document. (c) Paul Atherton Mr. Atherton is a qualified accountant, having qualified with Deloitte & Touche, and holds a degree in geology from Imperial College London. He has a corporate finance background with specific experience in the international mining and resource sectors. He joined HOC in 2000 and joined the HOC board of directors in (d) Gregory Turnbull Mr. Turnbull is the Regional Managing Partner of the Calgary office of the law firm of McCarthy Tétrault LLP. Mr. Turnbull has extensive knowledge of corporate governance issues and has acted for many boards of directors and special committees in that regard. Mr. Turnbull started his career with the law firm of MacKimmie Matthews in From 1987 to 2001, he was a partner with Gowlings LLP (formerly Code Hunter LLP). In 2001 and 2002, he was a partner with the law firm of Donahue LLP. Mr. Turnbull has been a partner with the law firm of McCarthy Tétrault LLP since July He joined HOC in (e) John McLeod Mr. McLeod is a professional engineer with over 36 years of varied resources extraction experience. He is the President of McLeod Petroleum Consulting Limited, the President, CEO and a director of California Oil and Gas Corporation and has held positions and has served on various boards including at Constellation Oil & Gas Ltd.; as President and CEO of Arakis Energy Company; as VP, Operations of Pengrowth Gas Company, Rally Energy Corp., CanArgo Energy Inc. and Canoro Resources. Currently, Mr. McLeod serves as a director of Paris Energy Inc., Consolidated Beacon Resources Ltd., Tuscany Energy Ltd., Diaz Resources Ltd. and Keeper Resources Inc. He joined HOC in

61 (f) General Sir Michael Wilkes General Sir Michael Wilkes, aged 67, Non-Executive Director General Sir Michael Wilkes KCB, CBE, retired from the British Army (the Army ) in 1995 as Adjutant General and Middle East Adviser to the British Government. As Adjutant General, Sir Michael was the most senior administrative officer within the Army and a member of the Army Board. During his distinguished career, he has seen active service across the world while also commanding at every level from Platoon to Field Army including commanding 22 Special Air Service Regiment and serving as the Director of Special Forces. Sir Michael is the Non-Executive Chairman of Cyberview Technology Ltd and a Non- Executive director of the Stanley Gibbons Group, both of which are listed on AIM. In addition he holds non executive positions on a number of private companies including Britam Defence and Trico Ltd and chairs the Advisory Board of PegasusBridge Fund Management Limited, a homeland security company. He joined the Group on 18 March Senior Manager Name Non-Executive Position Brian Smith... VP Exploration Brian Smith Mr. Smith has 30 years experience in the oil industry. He initially worked as an exploration geologist for Exxon in the North Sea and Gulf of Mexico. He subsequently joined Enterprise Oil where he managed various exploration projects in the Far East and Eastern Europe. He joined the Group in EMPLOYEES The table below sets out the number of people (full-time equivalents) employed by the Group including executive directors of HOC as at 31 December 2007 and 31 December 2006 and 2005: As at 31 December December December 2005 Total As at 31 December 2007, the Group had 89 employees (including full-time contractors and consultants, if any and Mr. Buckingham and Mr. Atherton). 41 employees are based in Russia, 5 employees are based in the KRI, 14 employees are based in the UK, 4 employees are based in South Africa, 3 employees are based in Switzerland, 1 employee is based in Canada and 21 employees are based in Uganda. 3. MAJOR SHAREHOLDER The following table contains certain information regarding the Major Shareholder. Number of Ordinary Shares (1) Percentage of Ordinary Shares (2) owned by the Major owned by the Major Name of Major Shareholder Shareholder Shareholder Albion Energy Limited... 84,540, % Notes: (1) This number includes the Ordinary Shares held by both the Major Shareholder and Mr. Anthony Buckingham as at Admission. (2) This figure includes the voting rights attaching to the Special Voting Share as well as the Ordinary Shares. The Major Shareholder is organised under the laws of Barbados and resides outside of Jersey. It may not be possible for investors to enforce judgments against the Major Shareholder which have been obtained in Jersey courts based on the civil liability provisions of applicable U.K. and Jersey securities legislation. Upon Admission, the Major Shareholder will hold approximately 33.2 per cent. of the issued and outstanding Ordinary Shares. The ultimate owner of the Major Shareholder is Mr. Anthony Buckingham, a Director and Chief Executive Officer of the Company and HOC. The Major Shareholder and Mr. Anthony Buckingham entered into a relationship agreement with the Company on 28 March The relationship agreement s purpose is to ensure that the Group is capable of carrying on business independently of the Major Shareholder and Mr. Anthony Buckingham (in his capacity as a shareholder of the Company) and that transactions and relationships with the Major 59

62 Shareholder and Mr. Anthony Buckingham are at arm s length and on normal commercial terms. The key terms and conditions of this agreement are set out in more detail in section 10.4 of Part X of this document. 4. CORPORATE GOVERNANCE Introduction The Directors recognise the importance of maintaining sound corporate governance practices. The Company will be in compliance with the corporate governance regime applicable to it as a Jerseyincorporated company. In addition, as its shares will be admitted to listing on the Official List and trading on the LSE, the Combined Code is also applicable. The Company currently complies with all aspects of the Combined Code except for the recommendation that at least half of the board of directors of a listed company, excluding the Chairman, should comprise non-executive directors determined by the board to be independent in character and judgement and free from relationships or circumstances which may affect, or could appear to affect, the director s judgement, and except for the recommendation that the Chairman of the Company should not be appointed to the Company s audit committee. As at Admission, only two of the six directors (excluding the Chairman who would also be considered an independent non-executive for the purposes of the Combined Code), John McLeod and General Sir Michael Wilkes, are considered by the Board to be independent according to the criteria of the Combined Code. Gregory Turnbull would not technically be considered to be independent according to the criteria of independence under the Combined Code, as he is a partner of McCarthy Tetrault LLP, the Canadian legal advisers to the Company. Notwithstanding Gregory Turnbull s technical lack of independence, the Board holds Gregory Turnbull to be independent in character and judgement and to thereby satisfy the Combined Code requirements for independence. In addition, the Chairman and each of the other Directors are independent of Anthony Buckingham. Additionally, despite being the Chairman of the Company, Mr Hibberd has been appointed to the Audit Committee (which is against the recommendations made in the Smith Guidance on the Combined Code) due to his recent and relevant financial experience, including his experience on corporate financial matters. However, upon the appointment of an additional non-executive director to the Board of Directors as soon as is reasonably practicable after Admission, the directors intend to rectify these deficiencies in the Company s compliance with the Combined Code. The Board Structure Upon Admission, the Board will consist of Michael Hibberd, Anthony Buckingham, Paul Atherton, Gregory Turnbull, John McLeod and General Sir Michael Wilkes. Mr. Hibberd, John McLeod and General Sir Michael Wilkes are the directors considered by the Board to be independent pursuant to the Combined Code. The Chairman s role is to ensure good corporate governance. His responsibilities will include leading the Board, ensuring the effectiveness of the Board in all aspects of its role, ensuring effective communication with shareholders, setting the Board s agenda and ensuring that all Directors are encouraged to participate fully in the activities and decision-making process of the Board. The Board has established an audit committee, a remuneration committee and a nomination committee. Audit Committee The Audit Committee is chaired by an independent non-executive director, and its other members are certain other non-executive directors of the Company. The Audit committee will meet not less than two times a year and will have responsibility for, amongst other things, monitoring the integrity of the Company s financial statements and reviewing its summary financial statements. It will oversee the Company s relationship with its external auditors and review the effectiveness of the external audit process. The committee will give due consideration to laws and regulations, the provisions of the Combined Code and the requirements of the Listing Rules. It will also have responsibility for reviewing the effectiveness of the Company s system of internal controls and risk management systems. The ultimate responsibility for reviewing and approving the interim and annual financial statements remains with the Board. The non-executive directors of the Company who have been appointed as the initial members of the Audit committee are considered by the Board to have recent and relevant financial experience. 60

63 Remuneration Committee The Remuneration Committee is chaired by an independent non-executive director and its other members are certain other non-executive directors of the Company. The Remuneration Committee will meet not less than at least once a year and will have responsibility for making recommendations to the Board: (i) on the Company s policy on the remuneration of Senior Manager and (ii) for the determination, within agreed terms of reference, of the remuneration of the Chairman and of specific remuneration packages for each of the Executive Directors and the Senior Manager, including pension rights, and any compensation payments. The Remuneration Committee will also ensure compliance with the Combined Code in this respect. Nomination Committee The Nomination Committee is chaired by an independent non-executive director and its other members consist of an independent non-executive director and an executive director. The committee will meet at least once a year and will, with effect from Admission, have responsibility for making recommendations to the Board on the composition of the Board and its committees and on retirements and appointments of additional and replacement Directors and ensuring compliance with the Combined Code. Model Code Upon Admission, the Company will adopt a code of securities dealings in relation to the Ordinary Shares, securities in group companies with stock exchange listings and other securities, to ensure compliance with the Model Code as published in the Listing Rules. The code adopted will apply to the Directors and other relevant employees of the Company including the Senior Manager. Remuneration Policy The purpose of the Company s remuneration policy is to enable it to recruit, retain and motivate the best people for the Company. It is the Company s aim to ensure that there is a clear link between the Company s performance and executive reward with pay varying with performance. Executive directors total reward consists of salary, annual bonus, long-term incentives and other benefits. The Remuneration Committee will review executive and non-executive rewards policies, the total rewards available to the executive and non-executive directors and the share-schemes in light of best practice in the U.K. The Company expects to seek Shareholder approval for a new performance-related executive incentive scheme at the next annual general meeting. It is the intention of the Company that over time it will provide executive rewards in a fashion in line with the Association of British Insurers and the National Association of Pension Funds guidelines, whilst maintaining an internationally competitive position. 61

64 PART III TECHNICAL REPORT Set out on the following pages is the statement of reserves data and other oil and gas information in relation to HOC (the Corporation ), effective 30 September 2007, prepared in accordance with the PRMS. 62

65 Goldsworth House, Denton Way, Goldsworth Part, Woking, Surrey, GU21 3LG, United Kingdom T +44 (0) F +44 (0) E rpsenergy@rpsgroup.com W 17MAR The Directors Heritage Oil Corporation #260 Petex Building, Ave Sw Calgary, Alberta, Canada, T2P OS5 Project Ref: ECV March 2008 Gentlemen, EVALUATION OF HERITAGE OIL CORPORATION S PETROLEUM ASSETS In response to your request, and the subsequent Letter of Engagement dated December 3 rd 2007, RPS Energy ( RPS ) has completed an independent evaluation of certain oil and gas properties in Russia, Oman, Uganda and Kurdistan in which Heritage Oil Corporation ( Heritage ) has an interest ( the Properties ). We have estimated a range of reserves and resources as at 30 th September 2007, based on data and information available up to 31 st December In estimating resources we have used standard petroleum engineering techniques, which combine geological and production data with information concerning fluid characteristics and reservoir pressure, where available. We have estimated the degree of uncertainty inherent in the measurements and interpretation of the data and have calculated a range of reserves and resources and risk factors in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (See Section 2.2). We have taken the working interest that Heritage has in the Properties, as presented by Heritage, and we have not investigated nor do we make any warranty as to Heritage s interest in the Properties. The data set included geological, geophysical and engineering data, together with reports and presentations pertaining to the contractual and fiscal terms applicable to the assets. In carrying out this review RPS has relied solely upon this information. Summary of Reserves and Resources Reserves Total gross reserves and net reserves attributable to Heritage s Properties are summarised in Table 1. United Kingdom Australia USA Canada Ireland Netherlands Malaysia RPS Energy Limited: Registered in England No , Centurion Court, 85 Milton Park, Abingdon, Oxfordshire OX14 4RY, United Kingdom 17MAR

66 Heritage Net Entitlement Heritage Net Working Reserves (at Base Case Gross Remaining Reserves Interest Reserves Price Forecast) Proved Proved Proved plus plus plus Proved Probable Proved Probable Proved Probable plus plus plus plus plus plus Proved Probable Possible Proved Probable Possible Proved Probable Possible (1P) (2P) (3P) (1P) (2P) (3P) (1P) (2P) (3P) Liquids (MMstb) LPG (MMstb) Gas (Bscf) Table 1: Summary of Heritage Reserves as of 30 th September 2007 The gross reserves and the net reserves attributable to each Heritage Property is given in Table 2. Heritage Net Heritage Entitlement Gross Net Working Reserves at Remaining Interest Base Case Reserves Reserves Price Forecast Bukha Field, Oman Condensate MMstb MMstb MMstb Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) LPG MMstb MMstb MMstb Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) West Bukha Field, Oman Oil MMstb MMstb MMstb Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) Condensate MMstb MMstb MMstb Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) LPG MMstb MMstb MMstb Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) Gas Bscf Bscf Bscf Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) Zapadno Chumpasskoye Field, Russia Oil MMstb MMstb MMstb Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) Table 2: Summary of Reserves for Each Property as of 30 th September

67 Resources A summary of the gross Contingent Resources and the net working interest Contingent Resources in Heritage s Properties is given in Table 3. Heritage Gross Estimate Working Interest Share (MMstb) (MMstb) 1C 2C 3C Equity 1C 2C 3C (Low) (ML) (High) (%) (Low) (ML) (High) Operator Kingfisher, Uganda Heritage Total The government has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5%. Table 3: Summary of Contingent Resources Reviewed by RPS A summary of the gross Prospective Resources and Heritage s 50 per cent. equity interest Prospective Resources (1) that have been reviewed by RPS is given in Table 4 along with the RPS estimate of Geological Probability of Success (GPoS),. N.B. The State has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5%. Heritage Working Gross Estimate Interest Share Low Best High Low Best High GPoS (p90) (p50) (p10) Mean (p90) (p50) (p10) Mean (%) Operator Block 3A, Uganda Kingfisher Main (Basal sand) Heritage Kingfisher North (Zone P1/M6) Heritage Kingfisher North (Basal sand) Heritage Pelican Main (Zone P1/M6) Heritage Pelican Main (Basal sand) Heritage Pelican North (Zone P1/M6) Heritage Pelican North (Basal sand) Heritage Pelican Shallow (Zone P1/M6) Heritage Pelican Shallow (Basal sand) Heritage Pelican West (Zone P1/M6) Heritage Pelican West (Basal sand) Heritage Pelican (light blue) Heritage Pelican (light green) Heritage Lead A (Zone P1/M6) Heritage Lead A (Basal sand) Heritage Lead B (Zone P1/M6) Heritage Lead B (Basal sand) Heritage Lead C (Zone P1/M6) , Heritage Lead C (Basal sand) , Heritage Block 1, Uganda Buffalo Heritage Crocodile Heritage Giraffe Heritage Hartebeest Heritage Total Mean... 2,756 1,378 The government has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5%. The chance or probability of discovering hydrocarbon volumes within the range defined. This is not an estimation of commercial chance of success. Arithmetic summation of individual P90, P50 and P10 quantities will not produce a total P90, P50 and P10. The process of statistical addition will, as a result of the central limit theorem, produce a P90 that is greater than the arithmetic sum of all P90 quantities and a P10 that is less than the arithmetic sum of all P10 quantities. The arithmetic sum of the mean quantities however is always equal to the mean of the distribution produced by the process of statistical addition. Table 4: Summary of Prospective Resources Reviewed by RPS (MMstb) (1) In the event of discovery and development, Heritage net entitlement resources will be a function of the contract terms and will be less than the net working interest resources. 65

68 As it is statistically incorrect to sum the p90, p50 and p10 volumes, the risked recoverable Contingent and Prospective resources in Blocks 1A and 3 have been consolidated stochastically and are quoted on a 100 per cent. basis (i.e. gross) in Table 5. Gross Risked Recoverable Resources (MMstb) p90 p50 p10 Mean , Table 5: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS Heritage has estimated potential resources in areas of their Ugandan blocks beyond seismic control. This was beyond the scope of the RPS evaluation given the time available. Conceptual leads are based on Heritage s regional and structural knowledge. At the time of this report, Heritage carry three conceptual leads in their portfolio: two of which are located in the northern part of Block 1 and one in the southwestern extremity of Block 3A. The unrisked mean STOIIP estimates from these evaluations are reported for completeness (Table 6) but RPS does not warrant these estimates and is not in a position to comment on the hydrocarbon potential of these areas. Mean STOIIP (MMstb) Block 3A, Conceptual Structure D Block 1, Conceptual Structure F... 2,925 Block 1, Conceptual Structure G... 2,925 Total... 6,314 Table 6: Heritage Unrisked Conceptual Leads (Not Reviewed by RPS) Economic Evaluation Economic valuation of reserves and resources are linked to a long term price forecast for Brent. The Base Case price forecasts, used for all valuations presented in this report, are given in. Table 7. US$/bbl, MOD 4Q onwards... +2% p.a. Table 7: RPS Price Base Case Forecasts (US$/bbl Money of the Day) 66

69 The post tax Net Present Value (NPV) at various discount rates 4 applying the RPS Base Case price forecasts are tabulated in Table 8. Post-Tax Net Present Value Economic (US$ Million, Money of the Day) Limit (1) 5% 7.5% 10% 12.5% 15% Net Heritage Share Bukha Field, Oman Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) West Bukha Field, Oman Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) Zapadno Chumpasskoye Field, Russia Proved Reserves (1P) Proved plus Probable Reserves (2P) Proved plus Probable plus Possible Reserves (3P) Note (1) Economic limit represents last year of input forecast production. Table 8: Post-Tax Valuation (Net Heritage Share) of Heritage s Reserves as of 30 th September 2007 The only 1C, 2C and 3C contingent and prospective resources in the portfolio are in Block 1 and 3A, Uganda and, at the request of Heritage, were not valued. Heritage was awarded a PSC for the Miran block in Kurdistan on 2 nd October There is insufficient data to estimate volumes of prospective resources in Miran at this stage. However in order to indicate possible value of the block RPS has, based on its detailed understanding of fields in the vicinity, made an estimate of the relationship between field size and value in the success case. Based on a low-mid-high range of 900 1,950 3,500 MMstb notional STOIIP, RPS has developed production and cost profiles and a relationship between field size and value in the success case. Average success case NPV 10 per recoverable barrel is given in Table 9: Miran... Table 9: Value (NPV 10 ) per recoverable barrel US$2.6 Success Case NPV 10 US$/per Recoverable Barrel (p50 case) Qualifications RPS is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, RPS does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report. Mr Roy Kelly, Technical Director, Reservoir Engineering for RPS Energy, has supervised the evaluation. Mr. Kelly has over 25 years oil and gas experience with international oil companies, as well as with international consultancies. He is a Member of the Society of Petroleum Engineers and a Fellow of the Energy Institute, as well as being a Chartered Petroleum Engineer. Other RPS Energy employees involved in this work hold at least a Masters degree in geology, geophysics, petroleum engineering or a related subject or have at least five years of relevant experience in the practice of geology, geophysics or petroleum engineering. Basis of Opinion The evaluation presented herein reflects our informed judgement based on accepted standards of professional investigation, but is subject to generally recognised uncertainties associated with the interpretation of geological, geophysical and engineering data. The evaluation has been conducted within 67

70 our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. However, RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the properties. RPS can not opine on the agreements between Oman and Iran concerning the development of the West Bukha Field. Our estimates of reserves and resources and value are based on the data set available to, and provided by Heritage. We have accepted, without independent verification, the accuracy and completeness of these data. The report represents RPS s best professional judgement and should not be considered a guarantee or prediction of results. It should be understood that any evaluation, particularly one involving exploration and future petroleum developments may be subject to significant variations over short periods of time as new information becomes available. This report relates specifically and solely to the subject assets and is conditional upon various assumptions that are described herein. This report must, therefore, be read in its entirety. This report was provided for the sole use of Heritage and its advisors on a fee basis. This report may be reproduced or redistributed to any other persons in its entirety. However in instances where excerpts only are to be reproduced or published, other than in relation to the initial public offering, this cannot be done without the express permission of RPS. RPS has given and not withdrawn its written consent to the issue of this document with its name included within it and with inclusion therein of its report and references thereto. RPS accepts responsibility for the information contained in the RPS report set out in this part of this document and to the best knowledge and belief of RPS, having taken all reasonable care to ensure that such is the case, the information contained in such report is in accordance with the facts and does not omit anything likely to affect the import of such information. Yours faithfully, RPS Energy 27MAR EurIng Roy T. Kelly, CEng, FEI Technical Director 68

71 RPS Energy Heritage Oil Competent Persons Report TABLE OF CONTENTS 1. DESCRIPTION OF ASSETS Overview Liabilities METHODS USED IN THIS REPORT General Reserves and Resource Classification Risk Assessment Contingent Resources Prospective Resources (Exploration Prospects) Uncertainty Estimation OMAN BLOCK Overview Bukha Field Database Geology and Geophysics In Place Volumes Petroleum Engineering Interaction with the West Bukha Field West Bukha Field Database Geology & Geophysics In Place Volumes Petroleum Engineering ZAPADNO CHUMPASSKOYE Data Available Geology Regional Setting Zapadno Chumpasskoye Field Petrophysics In Place Volumes Petroleum Engineering Reservoir Fluid Properties Well Performance & Deliverability Development Plan (Subsurface) Recovery Mechanisms Production Profiles Facilities and Costs UGANDA BLOCKS 1 & 3A Overview Data Available Geological Setting Geology & Geophysics Kingfisher Mapping Prospectivity Volumetrics Other Prospectivity Petroleum Engineering Production Profiles for Kingfisher and Other Block 3A Prospects Production Profiles for Block 1 Prospects Page 69

72 RPS Energy Heritage Oil Competent Persons Report Page 6. KURDISTAN MIRAN BLOCK Data Available Geology In place volumes Reservoir Engineering Facilities and Costs ECONOMICS Valuation Assumptions General Oil Prices Valuation Methodology Reserves Contingent and Prospective Resources Other (Miran) Oman Block Fiscal Regime and Contract Terms Price Assumptions Unrecovered Costs Valuation Summary Bukha Valuation Summary West Bukha Sensitivity to Oil Price Russia Zapadno Chumpasskoye Fiscal Regime and Contract Terms Price Assumptions Transportation Costs Tax Losses Valuation Summary Sensitivity to Oil Price Kurdistan Miran Block Fiscal Regime and Contract Terms Price Assumptions Valuation summary APPENDIX A: GLOSSARY OF TECHNICAL TERMS APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS

73 RPS Energy Heritage Oil Competent Persons Report List of Figures Figure 1: Omani Licence Location Map Figure 2: Russian Licence Location Map Figure 3: Kurdistan Licence Location Map Figure 4: Ugandan & DRC Licences Location Map Figure 5: Bukha Field Top Reservoir Depth Map Figure 6: Bukha Wet Gas History and Forecast Figure 7: Condensate Yield vs. Cumulative Wet Gas Production Figure 8: LPG yield vs. Cumulative Wet Gas Production Figure 9: Top Mishrif Depth Map Figure 10: West Bukha 3D inline Figure 11: 1P Production Profile for West Bukha Figure 12: 2P Production Profile for West Bukha Figure 13: 3P Production Profile for West Bukha Figure 14: Lower J 1 Sand RPS Net Pay Map (p50 Case) Figure 15: CPI for Well P3 over Reservoir Interval for p50 Saturation Case Figure 16: Well 226 Production History Figure 17: Well P3 Production History Figure 18: Illustration of Inverted Five-spot Patterns at Zapadno Chumpasskoye Figure 19: Oil Rate & Cumulative from Full Field Simulation Figure 20: Water Injection Rate & Cumulative from Full Field Simulation Figure 21: Average Reservoir Pressure from Full Field Simulation Figure 22: 1P Production Profile for Zapadno Chumpasskoye Figure 23: 2P Production Profile for Zapadno Chumpasskoye Figure 24: 3P Production Profile for Zapadno Chumpasskoye Figure 25: Seismic Section through Kingfisher 1 Well Figure 26: Reservoir Section in Kingfisher 1A Figure 27: RPS Cycle P1/M6 Depth Map, Block 3A Figure 28: RPS Top Reservoir Depth Map, Block Figure 29: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS (MMstb) Figure 30: Generic, Scalable Profile for Block 3A Prospects Figure 31: Generic, Scalable Profile for Block 1 Prospects & Leads Figure 32: Assumed Well Profiles for Miran Wells Figure 32: RPS Base Forecast Price Figure 33: Plot of Brent vs. URALS (Mediterranean) 1997 to Figure 34: Heritage Net NPV 10 vs. Notional Field Size Showing Price Sensitivity Page 71

74 RPS Energy Heritage Oil Competent Persons Report List of Tables Table 1: Summary of Heritage Reserves as of 30 th September Table 2: Summary of Reserves for Each Property as of 30 th September Table 3: Summary of Contingent Resources Reviewed by RPS Table 4: Summary of Prospective Resources Reviewed by RPS (MMstb) Table 5: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS Table 6: Heritage Unrisked Conceptual Leads (Not Reviewed by RPS) Table 7: RPS Price Base Case Forecasts (US$/bbl Money of the Day) Table 8: Post-Tax Valuation (Net Heritage Share) of Heritage s Reserves as of 30 th September Table 9: Success Case NPV 10 US$/per Recoverable Barrel (p50 case) Table 10: Summary of Heritage s Properties Table 11: Range of GIIP for the Bukha Field (Full Field Interest) from Novus Volumetrics Study February Table 12: West Bukha Volumetric Input Parameters Table 13: West Bukha In place Volumes 100 per cent. Basis Table 14: Summary of West Bukha & Henjam Well Tests Table 15: Initial Composition of West Bukha Wellstream Table 16: Estimated Product Yields from West Bukha Wellstream Table 17: Lower J 1 Sand Input Parameters Table 18: Zapadno Chumpasskoye, Lower J 1 Sand STOIIP Estimates (MMstb) Table 19: The p90 and p50 Drilling Schedule for Zapadno Chumpasskoye Table 20: Summary of Results for Zapadno Chumpasskoye Table 21: Uganda Volumetric Input Parameters Table 22: Kingfisher Discovery STOIIP and Contingent Resource Estimate (100 per cent. Basis) Table 23: Block 1 & 3A STOIIP and Prospective Resource Estimates (On-block, 100 per cent. Basis) Table 24: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS Table 25: Heritage Conceptual Leads Mean Un-Risked STOIP (100 per cent. Basis) Not Reviewed by RPS) Table 26: Summary of Kingfisher-1A Well Tests Table 27: Summary of Kingfisher-1 Fluid Properties Table 28: Assumptions Used For Profiles Table 29: Miran Field Range of Notional STOIIP Table 30: Assumptions Used in Miran Profiles Table 31: RPS Forecast Price Cases Table 32: Table of Base Case Forecast Prices Table 33: Bukha Post-Tax Valuation (Net Heritage Share) Table 34: Bukha Reserves Summary Table 35: West Bukha Post-Tax Valuation (Net Heritage Share) Table 36: West Bukha Reserves Summary Table 37: Sensitivity of Bukha NPV 10 to Oil Price Page 72

75 RPS Energy Heritage Oil Competent Persons Report Page Table 38: Sensitivity of West Bukha NPV 10 to Oil Price Table 39: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share) Table 40: Zapadno Chumpasskoye Reserves Summary Table 41: Sensitivity of Zapadno Chumpasskoye NPV 10 to Oil Price Table 42: Net NPV 10 and Average for NPV 10 /stb for a Range of Notional Field Sizes

76 RPS Energy Heritage Oil Competent Persons Report 1. DESCRIPTION OF ASSETS 1.1. Overview Heritage has a portfolio of assets that include production in Oman (Bukha) and Russia (Zapadno Chumpasskoye), undeveloped discoveries in Oman (West Bukha) and Uganda (Kingfisher) and an exploration portfolio including Uganda and Kurdistan and new exploration licences in Mali, Malta and Pakistan. Details of the assets, provided by Heritage, are summarised in Table 10, below: Licence Area (sq km) Date Awarded Heritage Equity Partners OMAN Block April % Rak Petroleum, LG RUSSIA Zapadno September % Chumpasskoye UGANDA Block , July % Tullow Oil Block 3A... 2, September % Tullow Oil KURDISTAN Miran Block... 1, October % D.R. CONGO Block I... 3, Signed July % Tullow Oil, (awaiting Presidential Decree) Cohydro Block II... 2, Signed July % Tullow Oil, (awaiting Presidential Decree) Cohydro MALI Block , July % Centric Energy Block , June % Centric Energy MALTA Area , December % Area , December % PAKISTAN Sanjawi Permit.. 2, November % Sprint Energy, Trakker Energy The government has the right to back-in for up to 15% which would reduce the Heritage net working interest to 42.5%. The government has the right to back-in for up to 25% which would reduce the Heritage net working interest to 75%. Table 10: Summary of Heritage s Properties As the licences in Malta, Mali and Pakistan were signed after the effective date of this report, only the properties in Oman, Russia, Uganda and Kurdistan were reviewed by RPS for this report. 74

77 RPS Energy Heritage Oil Competent Persons Report Locations of the properties are shown in Figure 1 to Figure 4. Figure 1: Omani Licence Location Map 21FEB Figure 2: Russian Licence Location Map 21FEB

78 RPS Energy Heritage Oil Competent Persons Report 21FEB Figure 3: Kurdistan Licence Location Map BLOCK 5 Neptune DEMOCRATIC REPUBLIC BLOCK 1 Heritage OF CONGO BLOCK I Tullow Ngassa-1 Waraga-1 BLOCK 2 Tullow BLOCK II Tullow Mputa-2 Mputa-1 Mputa km Kingfisher-1 Mputa-3 Nzizi-1 Nzizi-2 LEGEND Permits BLOCK III Open BLOCK 3A Heritage BLOCK 3B Open BLOCK 3C Open Heritage PSA BLOCK 3D Open Albert Graben Country Border BLOCK IV Open BLOCK 4A Open UGANDA Oil Well BLOCK V Dominion BLOCK 4B Dominion 25MAR Figure 4: Ugandan & DRC Licences Location Map 76

79 RPS Energy Heritage Oil Competent Persons Report 1.2. Liabilities The work programmes associated with the PSAs in Uganda and Kurdistan are discussed in Section 7. In addition to the exploration work programme in the Kurdistan PSA, there is also a commitment to build a small refinery, which should have a capacity of 20,000 barrels of oil per day, in strategic partnership with the Kurdistan Regional Government (KRG). Heritage has advised that the refinery is scheduled to be operational to design specification within approximately two years. RPS has not considered the cost liability or potential revenues from this refinery project in the notional evaluation of Miran. 2. METHODS USED IN THIS REPORT 2.1. General The evaluation presented in this Competent Persons Report ( CPR ) has been conducted within our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the properties. Our estimates of potential resources and risks are based on the limited data set available to, and provided by, Heritage. We have accepted, without independent verification, the accuracy and completeness of these data. Volumes and risk factors are presented in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (See Section 2.2) Reserves and Resource Classification Reserves or resources are estimated according to the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (PRMS). The PRMS Definitions are summarised in Appendix B. In estimating reserves and resources we have used standard petroleum engineering techniques. These techniques combine geological and production data with detailed information concerning fluid characteristics and reservoir pressure. RPS has estimated the degree of uncertainty inherent in the measurements and interpretation of the data and has calculated a range of recoverable reserves. RPS has assumed that the working interest in each asset advised by Heritage is correct and RPS has not investigated nor does it make any warranty as to Heritage s interest in these properties. Hydrocarbon resource and reserve estimates are expressions of judgement based on knowledge, experience and industry practice and are restricted to the data made available. They are therefore imprecise and depend to some extent on interpretations, which may prove to be inaccurate. Estimates that were reasonable when made may change significantly when new information from additional exploration or appraisal activity becomes available Risk Assessment For all prospects and appraisal assets estimates of the commercial chance of success for Contingent Resources and estimate of geological chance of success for Prospective Resources have been made. In PRMS the former is called Chance of Development (CoD) and the latter Chance of Discovery (also CoD) in the PRMS system. To avoid confusion with acronyms we have used the term Geological Probability of Success (GPoS) in this document synonymously with Chance of Discovery Contingent Resources The chance of success in this context means the estimated chance, or probability, that the volumes will be commercially extracted. A Contingent Resource includes both proved hydrocarbon accumulations for which there is currently no development plan or sales contract and proved hydrocarbon accumulations that are too small or are in reservoirs that are of insufficient quality to allow commercial development at current prices. As a result the estimation of the chance that the volumes will be commercially extracted may have to address both commercial (i.e. contractual or oil price considerations) and technical (i.e. technology to address low deliverability reservoirs) issues. 77

80 RPS Energy Heritage Oil Competent Persons Report Prospective Resources (Exploration Prospects) Unlike risk assessment for Contingent Resources, when dealing with undrilled prospects there is a more accepted industry approach to risk assessment for Prospective Resources. It is standard practice to assign a Geological Probability of Success (GPoS) which represents the likelihood of source rock, charge, reservoir, trap and seal conspiring to result in a present-day hydrocarbon accumulation. RPS assesses risk by considering both a Play Risk and a Prospect Risk. The chance of success for the Play and Prospect are multiplied together to give a Geological Probability of Success (GPoS). We consider three factors when assessing Play Risk: source, reservoir, seal and we consider four factors when assessing Prospect Risk: trap, seal, reservoir and charge. The result is the chance or probability of discovering hydrocarbon volumes within the range defined (Section 2.4). It is not an estimation of commercial chance of success Uncertainty Estimation The estimation of expected hydrocarbon volumes is an integral part of the evaluation process. It is normal practice to assign a range to the volume estimates because of the uncertainty over exactly how large the discovery or prospect will be. Estimating the range is normally undertaken in a probabilistic way (i.e. using Monte Carlo simulation), using a range for each input parameter to derive a range for the output volumes. Key contributing factors to the overall uncertainty are data uncertainty, interpretation uncertainty and model uncertainty. Volumetric input parameters, Gross Rock Volume (GRV), porosity, N:G ratio, S w, fluid expansion factor (Eo or Eg) and recovery factor, are considered separately. RPS has internal guidelines on the best practice in characterising appropriate input distributions for these parameters. Systematic bias in volumetric assessment is a well-established phenomenon. There is a tendency to estimate parameters to a greater degree of precision than is warranted (2) and to bias pre-drill estimates to the high side (3). Rose and Edwards (3) observe the tendency towards assessing volumes in too narrow a range, with overly large low-side and mean estimates. RPS uses benchmarked p10/p90 ratios and known field-size distributions to check the reasonableness of estimated volumes. 3. OMAN BLOCK Overview Heritage via Eagle Energy (Oman) Ltd holds a 10 per cent. equity in one licence (Block 8) situated offshore Oman. This licence was acquired in 1996 and contains the currently producing Bukha Field and the undeveloped West Bukha/Henjam discovery. This block is in a region of complex structures with a multiphase compressional origin. Deformation began in the mid to late Cretaceous with thrust emplacement of the S ophiolite, followed by salt diapirism, and finally compression and wrenching related to the mid Miocene Zagross orogeny. The two fields occur in structures which all have the form of anticlines related to backthrusts that probably originated in advance of the S ophiolite overthrust, but were modified by continued thrusting and wrench fault movement in the mid Miocene. The reservoirs are shelf limestones of early to mid Cretaceous age. The Aptian age Thamama Group limestones are sealed by Albian Nahr Umr Formation shales. These units are followed by a further series of shelf limestones of late Albian to Cenomanian age: termed the Mauddud, Khatiyah and Mishrif (=Sarvak in Iran) Formations. Deposition of these units was then followed by the major 92Ma (Turonian) unconformity, which is related to the emplacement of the S Ophiolite. The extent and depth of this unconformity increases towards the main thrust front in onshore Oman (hence the younger reservoirs are missing in the Bukha areas towards the west). This erosive phase was followed, firstly by the transgressive Laffan shale, and then by the shallow water carbonate Ilam Formation. Both formations are of Coniacian-Santonian age. Late Cretaceous sedimentation was in a foredeep west of the thrust front, in which the Aruma Group flysch was deposited. Phases of structural growth continued in the Palaeocene, Oligocene and Late Miocene. The Miocene unconformity is particularly strongly developed, and is locally highly angular showing that most structural growth was just pre late Miocene. (2) Rose, P.R., Dealing with Risk and Uncertainty in Exploration: How Can We Improve? AAPG Bulletin, 71 (1), pp (3) Rose, R.P. and Edwards, B., Could this prospect turn out to be a mediocre little one-well field? Abstract, AAPG Bulletin, 84(13) 78

81 RPS Energy Heritage Oil Competent Persons Report 3.2. Bukha Field The Bukha gas field is located in the Straits of Hormuz approximately 12 km off the west coast of the Musandam Peninsula. The field was discovered by IPC in Three wells have been drilled on the structure. Bukha-1 and Bukha-2 are situated close to the crest of the structure. Bukha-3 was drilled directionally from the Bukha-1 surface location down flank to the southwest. The field has been on production from two wells, Bukha-1 and -2, since Database The Bukha Field is covered by 2D seismic data that was acquired over a considerable span of time from 1974 to These data have been the subject of a reprocessing exercise in Despite this reprocessing numerous problems still exist of the type to be expected with 2D data in areas of high dips namely migration misties, out of plane reflections etc. A 3D survey was acquired during 2006/07, but is still being processed by the operator. Production data from the field were provided by Heritage Geology and Geophysics The field consists of a single contiguous NE-SW trending fault and dip closed structure covering an area of approximately 35 sq km. The tilted fault block is controlled by two main faults; the Tibat thrust and the Bukha back-thrust. Fractured carbonate reservoirs within the Cretaceous Mauddud and Thamama Formations occur at depths of between 2,900 and 3,500 m TVDSS. The Mauddud Formation has an average thickness of 52 m and is separated from the underlying Thamama Formation by the Nahr Umr shale with an average thickness of 106 m. The Thamama reaches a total thickness of around 650 m. Figure 5 shows a depth structure map of the Bukha Field. The area above structural spill that lies to the north of the North Bukha fault is known as North Bukha and it is not known whether this area is being drained by the production wells. If it becomes apparent that the reserves in the North Bukha area are not being produced then an appraisal well may be drilled. Figure 5: Bukha Field Top Reservoir Depth Map 21FEB

82 RPS Energy Heritage Oil Competent Persons Report In previous reserves reports for Heritage, RPS has reviewed the geology of the field. As no new geological or geophysical data have been made available, the previous information was used as a basis for this report, updated with the 2006/07 production data. The time to depth conversion of the seismic interpretation is problematical in this region as there are rapid lateral velocity changes over the interval sea level to Top Ilam/Mauddud. The reasons for these velocity variations are not precisely understood and would appear to be a complex interplay of several contributing factors. To account for these velocity variations a number of different depth conversion methodologies have been utilised to generate a range of possible structures and the resulting maps have been used to generate minimum, most likely and maximum GRVs for reserve determination purpose. The Mauddud reservoir tends to be thin (c.50 m thick), while the Thamama is a thick unit (several hundred metres), comprising several upward coarsening cycles with few effective intra-formational seals. The reservoirs are fine-grained low porosity limestones, with wackestone and grainstone textures. They are layered, with dense zones, which may act as horizontal baffles or seals. Background matrix porosity is low (0-4 per cent.), but porosity spikes of up to 10 per cent. do occur. The Thamama tends to be slightly tighter than the Mauddud reservoir. Stylolites are common, probably concentrated in the tight zones. In Henjam/ West Bukha there are two higher porosity horizons, which are believed to be due to karstic erosion, and therefore may be laterally continuous. The lower is better developed, and is located at the top of the Mauddud. The upper karstic horizon is at the top of the Mishrif E unit. The presence and distribution of fractures is crucial to the ability of the reservoirs to sustain commercial flow rates. Fractures appear to be rarely sampled in cores, but are believed to be pervasive. Two issues concerning fractures are: 1) whether there is connectivity through the fractures between the vertically stacked reservoirs (so that a common GWC exists), and 2) what porosity cut-off to apply to the matrix, when permeability is so fracture dependant. The Mauddud and Thamama appear to be sealed from each other by the Nahr Umr shale, which allows for stacked separate reservoirs and thus different GWCs (unless in communication via formations on the downthrown sides of faults) In Place Volumes Production comes from both the Mauddud and the Thamama Formations, each of which should be treated as an individual reservoir. In addition to the sensitivity provided by the range of GRVs described above several other factors affect the possible range of reserves in the Bukha Field. The most important of these are the porosity cut-off used to define net reservoir and the GWCs assumed. None of the wells in the field intersects a GWC and therefore it is only possible to establish a lowest known gas level that can be used as a minimum case. The structural spill point can be used as a maximum case. The field operator (currently Rak Petroleum PCL) carried out a volumetric evaluation to determine the range of possible GIIP values in These were reviewed by RPS in the 2006 reserves review and they appear to a reasonable attempt to capture the range of uncertainty. There have been no new data to revise these estimates. GIIP (Bscf) Reservoir p90 p50 p10 Mauddud Thamama Total N.B. The totals are the p90, p50 and p10 of the stochastically consolidated distributions Table 11: Range of GIIP for the Bukha Field (Full Field Interest) from Novus Volumetrics Study February Petroleum Engineering Reservoir Temperature, Pressure and Gas Properties Reservoir properties at the time of discovery were a pressure of 7,147 psig and a temperature of 295 F. Currently pressures from Bukha-1 and Bukha-2 are about 350 psia. The Bukha field is a gas condensate reservoir (in the Thamama and Mauddud Formation). Historic production data indicate that the field came off a plateau (of about 43 MMscf/d) in 2003 and average wet gas rates in 2007 were around 23.3 MMscf/d. The condensate yield from the field was initially above 100 stb/mmscf. As the field is produced by depletion only (i.e. without pressure support) the yield has 80

83 RPS Energy Heritage Oil Competent Persons Report steadily declined and during 2007 the average condensate yield was 40.9 stb/mmscf, while the LPG yield has increased to 27.2 stb/mmscf in Development The Bukha field has been developed using a minimum facilities, unmanned platform with one sub-sea well (Bukha-1) and one platform-completed well (Bukha-2). Bukha-1 is tied to the platform via a 6 flexible flow line of 1.2 km. The platform is connected to the onshore gas processing plant via a 16 carbon steel pipeline of 34 km. Cumulative production to the end of 2007 was approximately 199 Bscf reservoir gas, 13.1 MMstb condensate and 4.5 MMstb LPG Production Forecasts To obtain a forecast for wet gas this year, the 2007 monthly data from January up to September 2007 were used. RPS had no data for the subsequent months. The historic data suggests a clear decline in the gas production. However, field performance has exceeded RPS s previous forecast (for 2006 year-end reserves). To this end, and honouring the most recent data, linear trends were fitted to a wet gas rate vs. cumulative wet gas plot to obtain 1P and 2P cases, and a hyperbolic trend was fitted for the 3P case (Figure 6). 60 Wet Gas Rate - History Wet gas rate P Forecast 2P Forecast Wet Gas Rate (MMscf/d) P Forecast Dec Figure 6: Bukha Wet Gas History and Forecast 21FEB Condensate Gas Ratio (CGR) plotted against cumulative wet gas shows how the condensate yield changes along with the field production. A clear and unique trend was visible in line with expected behaviour and it is been used for the 1P, 2P and 3P cases (Figure 7). 81

84 RPS Energy Heritage Oil Competent Persons Report Wet Gas Rate (MMscf/d) Wet Gas Rate - History Wet gas rate 2007 October 2007 cut off Condensate Yield Condensate yield 2007 Condensate match Condensate yield (bbls/mmscf) History Forecast Cumulative Gas (Bscf) Figure 7: Condensate Yield vs. Cumulative Wet Gas Production 21FEB In order to create a LPG forecast, a plot of LPG yield vs. cumulative wet gas was inspected (Figure 8). In previous years, the historical data appeared to be following a quite steady line, but in recent years it has come to follow the typical behaviour of C 3 and C 4 fractions in a typical gas condensate reservoir. A polynomial equation was fitted to the historical data for the 1P case and another polynomial equation was fitted for the 2P and 3P cases. LPG is split into its components C 3 and C 4 based on sales statements from 2007, that being 43 per cent. for propane and 57 per cent. for butane Wet gas rate (MMscf/d) Wet Gas Rate - History Wet gas rate 2007 October cut off LPG Yield 1P Forecast 2P & 3P Forecast History Forecast LPG yield (bbls/mmscf) Cumulative wet gas (Bscf) Figure 8: LPG yield vs. Cumulative Wet Gas Production 21FEB Interaction with the West Bukha Field After considering the impact of the West Bukha production coming on stream via the Bukha platform, changes were made to make the forecast more realistic (4). West Bukha will flow at high pressures initially, such that the Bukha wells, now flowing at low wellhead pressures with chokes fully open, will not be able to 82

85 RPS Energy Heritage Oil Competent Persons Report flow against the higher back-pressure. The forecast for the West Bukha production start-up has been assumed, conservatively, by RPS to be January 2009 although the Operator has advised Heritage that production is targeted for 3 rd Quarter It has been assumed that Bukha will cease production temporarily while West Bukha pressures remain high. West Bukha will reach a point when the flowing pressure will be sufficiently low that the Bukha field would be brought back into production and both fields would produce at the same time through the same pipeline to the Ras Al Khaimah Gas Commission ( RAKGAS ) plant West Bukha Field The West Bukha/Henjam gas field is located in the Straits of Hormuz approximately 22 km west of the Bukha field in about 90m of water. The field straddles the border between Iran and Oman. The field was discovered in 1975 by the Henjam-1 well in Iran and was subsequently appraised with Khasab-1, drilled by Elf in Oman in Khasab-1 was drilled off structure and encountered water. A second appraisal well, West Bukha 1, drilled in 1987 by IPC found gas condensate but at the time failed to produce commercial rates. The National Iranian Oil Company (NIOC) acquired 3D seismic over the field and approximately 80 per cent. of the area covered was made available to the Block 8 licence holders. It is understood that attempts to negotiate a possible joint field development with Iran and Oman failed to produce an agreement. Although such negotiations are continuing, the Block 8 partnership has since decided to pursue an Oman only development. Heritage advises that the Operator has secured agreement from the Sultan of Oman s government to develop the field. However, public domain data from NIOC in Iran suggests that an Iranian development is likely to proceed imminently. RPS is not in a position to opine on the legal status of the development Database The West Bukha field is covered by 2D seismic acquired from , this data is poor quality. The Iranian National Oil Company acquired a 3D survey over the West Bukha field which covers the Oman and Iranian parts of the field. This survey is high frequency in the upper section but very good quality at the reservoir depth. The West Bukha 3D has been depth migrated, this data was used prior to the drilling of the West Bukha-2 well where it was found that velocities had been inaccurately modelled. Well Data from four wells was made available, West Bukha-1, West Bukha-2, Henjam-1 and Khasab-1. Full log suites were made available for these wells as well as geological and test data. A static geological model was provided Geology & Geophysics The field consists of a single contiguous NW-SE trending fault and dip closed structure covering an area of approximately 62 sq km. Fractured carbonate reservoirs occur within the Cretaceous Ilam, Mishrif, Mauddud and Thamama Formations at depths of between 3,600 and 4,200 m TVDSS. There is considerable variation in thickness of the Ilam and Mishrif Formations linked to sedimentary deposition along a carbonate shelf edge. The Ilam and Mishrif Formations are thickest in Iran where, in Henjam 1, they attained a gross thickness of more than 100 m whilst within the field boundary in Oman these formations thin to around 50 m. The Mauddud Formation has an average thickness of approximately 80 m throughout the field and is separated from the underlying Sabsab and Thamama Formations by the Nahr Umr shale with an average thickness of 136 m. The Sabsab and Thamama reaches a total thickness of around 400 m. The Operator and Heritage have interpreted three horizons across the West Bukha field; Top Ilam, Top Nahr Umr and Top Thamama. The first two horizons define the structural envelope of the Mishrif-Mauddud reservoir (Figure 9). (4) We note that this consequence has been previously ignored. However, the operator has stated (Sept.07 OCM Minute) that he expects Bukha production to cease once West Bukha comes on stream. 83

86 RPS Energy Heritage Oil Competent Persons Report Figure 9: Top Mishrif Depth Map 21FEB The Top Ilam and Top Nahr Umr reflectors are strong and easy to correlate across the field (Figure 10). There is a large increase in velocity at the top of the Ilam which results in a very prominent reflector. The interpretation ties all of the wells in the field except for the Khasab-1 well where the interpretation is some 30 msec deeper than the well top. The TD relationship at Khasab-1 is calculated from uncalibrated sonic logs and therefore the formation tops in this well may not be accurate. RPS has reviewed the interpretation and mapping of these reflectors and considers them to be reasonable. The Top Thamama is a much weaker reflector than the Top Ilam or Top Nahr Umr. RPS has reviewed the interpretation and mapping of these reflectors and considers them to be reasonable. The interpretation sensibly follows structural trends and the horizon ties the formation tops in the wells where the Thamama has been penetrated. 84

87 RPS Energy Heritage Oil Competent Persons Report Figure 10: West Bukha 3D inline FEB The Operator maps are based on a more simplistic approach to depth conversion than in previous studies, which used a complex interval velocity method for depth conversion as shallow salt was thought to impact on velocities. Despite this approach West Bukha-2 penetrated the reservoir some 80 m shallower than predicted which invalidated this method. The current maps are based on an average velocities for each horizon derived from well data. There is little variation in average velocities across the field, although an eastward decrease in average velocity is not supported by well data and velocities at the extreme west and east of the model exceed the velocities in the wells although not markedly. RPS considers the depth conversion reasonable. A facies model has been developed by the Operator which has been reviewed by RPS and appears reasonable. The Mauddud shows little variation in thickness across the field and the subunits are the same in all wells drilled in the field. All nine sub units across the field are carbonate platform facies. Correlation with the Bukha filed shows that Mauddud sub-units 7, 8 and 9 are missing in Bukha which indicates the position of the shelf is between West Bukha and Bukha. Correlation with Bukha and Tibat shows a back-stepping carbonate platform from the south east to north west during deposition of the Mauddud. Each well in the West Bukha Field has the same Mauddud sub-units, suggesting that West Bukha is the final carbonate platform and hence has a complete Mauddud section. The Mishrif varies considerably in thickness across the field with 3 sub- units present at West Bukha-2 and Henjam-1, whereas West Bukha-1 and Khasab-1 have only the deepest Mishrif-1 sub- unit. The Henjam-1 and West Bukha-2 wells are interpreted to be on the carbonate platform during Mishrif deposition with West Bukha-1 and Khasab-1 existing on the carbonate slope. Heritage has used an isopach thickness map to determine the extent of the platform and the position of the slope. This is a reasonable approach as variation in the thickness of the Mishrif is the predominant variable in the thickness of the Ilam-Nahr Umr isopach that was used to define the platform. This thickness variation is also visible on the seismic where a single trough across the field at the Top Ilam becomes a trough-peak-trough to the north. Reservoir quality and thickness are interpreted to improve to the north where the Mishrif is thickest. If this is the case, wells drilled to the SW of West Bukha-2 are unlikely to encounter the better carbonate platform facies and the reservoir will be similar to West Bukha In Place Volumes RPS calculated in place volumes for the Mishrif/Mauddud and for the Thamama. 85

88 RPS Energy Heritage Oil Competent Persons Report As discussed above the Mishrif-Mauddud reservoir thickness varies considerably over the field. The majority of this variation occurs in the Mishrif Formation. The thicker isopachs represent the platform carbonates drilled at Henjam-1 and West Bukha-2 as opposed to the slope facies drilled at West Bukha-1 and Khasab-1. These platform carbonates are cleaner better reservoir facies and therefore their extent has been modelled when calculating GRV. Isochron maps have been used to determine the extent of this better reservoir facies in line with previous studies carried out by Indago and Novus. Gross rock volumes were calculated from the Top Mishrif to Top Nahr Umr for the whole field. The GRV of the better Mishrif reservoir was calculated from the top Mishrif to top Mishrif 1 unit over the area interpreted to be part of the platform above the fluid contact. The Mishrif 2 and 3 units GRV was then removed from the total field GRV so that separate reservoir parameters could be applied to both GRVs. These two separate cases were then consolidated. For the Top Mishrif reservoir, a surface was calculated by isopaching 23 m down from the Top Ilam depth surface to account for the average thickness of the Ilam and Laffan units across the field (16-27 m in the wells). The Top Mishrif 1 surface was calculated by isopaching 75 m up from RPS s Top Mishrif surface to account for the Mishrif 2 and 3 units present in Henjam-1 (61m) and West Bukha-2 (90m). The GRV for the Thamama Reservoir was calculated from Top Thamama to the fluid contact for all cases. RPS has independently reviewed the petrophysical data in West Bukha-1/1A and -2. Net to gross values in all cases were set to 100 per cent. as the pervasive fractures in the reservoir probably connected the full volume of matrix porosity. Clay volumes within the reservoir sequences are not high and there are few individual shaley beds, both the Thamama and the Mishrif-Mauddud are clean limestones with a few thin shale beds. Porosity in these tight carbonate reservoirs is very low. Average values for both reservoirs is between 1 and 3 per cent. The Mishrif-Mauddud porosity was determined from petrophysics carried out on West Bukha-1 and West Bukha-2A. The Mishrif-Mauddud was separated into two zones for volumetric purposes; the Mishrif1-Mauddud unit and the Mishrif 2 and 3 units only being found in the northern part of the field. These units have slightly better reservoir parameters being clean platform carbonates as opposed to the slope facies found at West Bukha-1. The Thamama porosity was determined from petrophysics carried out on West Bukha-1 and West Bukha-2A. Water saturation is the most poorly constrained reservoir parameters. Low porosities make the determination of S w difficult and S w varies markedly between the West Bukha-1 and -2 wells. A wide range of S w has been used in the probabilistic calculation. A normal distribution of S w was used for both reservoirs with a p90 value of 49 per cent. in both reservoirs and a p10 value of 18 per cent. in the Mishrif and 30 per cent. in the Thamama, respectively. FVF factors were recalculated by RPS and a range of values were applied in the volumetric evaluation. There is some uncertainty in the positions of the Gas Water Contact in the two reservoirs. Log evaluation is inconclusive and fluid contacts have been estimated from RFT data and production test results. Results from West Bukha-2 indicate that Mishrif-Mauddud reservoir is not connected to the Thamama reservoir. For the Mishrif-Mauddud a triangular distribution of possible contact depths was used to model the uncertainty. A minimum contact of 4,040 m TVDSS was taken from the deepest hydrocarbons tested in West Bukha-2A, the most likely contact of 4,300 m TVDSS was based on RFT pressure data from wells in the field and a maximum contact of 4,310 m TVDSS was based on the highest known water in the field in the Khasab-1 test. For the Thamama a similar approach was used to model the uncertainty in water contact. Pressure data is inconclusive so a normal distribution based on a minimum contact of 4,163 m TVDSS, the lowest known oil in West Bukha-2A, and a maximum contact of 4,268 m TVDSS from pressure data was used. 86

89 RPS Energy Heritage Oil Competent Persons Report A summary of input rock and fluid properties is given in Table 12. Low Mid High Mishrif/Mauddud GRV... MM m 3 1,671 3,844 4,023 N:G... % Porosity-Mish-Maudd... % Porosity- Mish 2&3... % Sw... % /FVF... stb/rb Thamama GRV... MM m ,091 1,622 N:G Porosity... % Sw... % /FVF... stb/rb Table 12: West Bukha Volumetric Input Parameters In-place volumes were calculated probabilistically for the Mishrif/Mauddud and Thamama reservoirs for both the whole field and for the portion of the field in Omani waters. Whole Field (MMstb) Omani Waters (MMstb) Reservoir p90 p50 p10 p90 p50 p10 Mishrif/Mauddud Thamama Total N.B. The totals are the p90, p50 and p10 of the stochastically consolidated distributions. Table 13: West Bukha In place Volumes 100 per cent. Basis Petroleum Engineering Reservoir Fluid Properties There has previously been debate amongst the legacy owners of the West Bukha field as to whether the reservoir contains a rich gas (or condensate ) type fluid, or a volatile oil, and latterly the field owners have come to the conclusion that the reservoir fluid is a volatile oil. Such confusion is common when the fluid is a near-critical point fluid, as liquid:gas ratios during short well tests can be misleading, and representative sampling difficult. We note that the NIOC has always maintained that the field is a volatile oil field. Upon examination of the fluid samples captured in wells Henjam-1 and West Bukha-2, and the laboratory analyses of same, we have concluded that the fluid is more likely to be oil at reservoir conditions, for the following reasons: The methane ( C 1 ) content is below 60mol per cent.; The test separator GOR is <3,000 scf/stb; The Heptanes plus ( C 7 + ) content of the reservoir fluid is > 12 mol per cent.; The CVD experiment yielded 100 per cent. liquid saturation at the saturation pressure; A differential vaporisation experiment was performed and a bubble point measured (this would not be possible on a gaseous fluid). The initial reservoir fluid composition is as shown in Table 3.6 overleaf. The source of this is the PVT analysis of samples from DST 2 in the Mishrif Formation in Well West Bukha-2; the reservoir fluid in the underlying Thamama formation is similar. Approximately 1.4 mol per cent. H 2 S has been measured in the reservoir samples, and approximately 14 mol per cent. CO 2 and N 2. 87

90 RPS Energy Heritage Oil Competent Persons Report The initial reservoir pressure and temperature of the Mishrif Formation has been measured as 7,285 psia and 295 F (values are commensurately higher in the deeper Thamama Formation) Well Testing & Deliverability There have been numerous tests in the West Bukha/Henjam wells over the years, and these are summarised in Table 14, below. Interval Oil Rate Gas Rate Choke WHFP Well DST # Date of Test (m MD) Formation (stb/d) (MMscf/d) ( ) (psig) Hengam ,970-3,980 Mauddud 2, /64 3,640 (10m interval) Hengam April, ,072-4,110 Thamama / (38m interval) Hengam July, ,732-3,907 Mishrif 5, /64 1,477 (35m interval) West Bukha-1A... 1 June, ,086- Thamama 1, /64 1,467 2 June, ,846- Mauddud / June, ,729- Mishrif / West Bukha-2A... 1 Nov., ,521-3,541 Thamama 4, /64 1,652 (20m interval) 2 Nov., ,005-4,127.5 Mishrif 8, /64 2,087 (122.5m interval) (inferred) Table 14: Summary of West Bukha & Henjam Well Tests It can be seen that test rates vary greatly, which is typical of the subject formations in the Gulf region. Productivity is enhanced where pervasive, open fractures are encountered, and matrix reservoir quality is such that little or no flow is possible without the presence of fractures (matrix permeability is typically less than 1 md). The latest well (West Bukha-2) provides a modern suite of data, including downhole pressure data from the DSTs, and we have analysed the Mishrif test (DST #2). The key results of our analysis are as follows: Permeability, k e md Total skin, S Omega, (a measure of fracture storage) Lambda, x 10-7 (a measure of matrix-fracture flow) These results are typical of the dual porosity system in these formations (very low matrix permeability, negative skin), and demonstrates that the wells must intersect a fracture system to be capable of commercial flow rates. No depletion was detected during the test, and the well s PI was approximately 6.4 stb/d/psi. Component Mole % Weight % H 2 Hydrogen H 2 S Hydrogen Sulphide CO 2 Carbon Dioxide N 2 Nitrogen C 1 Methane C 2 Ethane C 3 Propane ic 4 i-butane nc 4 n-butane C 5 Neo-Pentane ic 5 I-Pentane nc 5 n-pentane C 6 Hexanes M-C-Pentane Benzene Cyclohexane C 7 Heptanes

91 RPS Energy Heritage Oil Competent Persons Report Component Mole % Weight % M-C-Hexane Toluene C 8 Octanes E-Benzene M/P-Xylene O-Xylene C 9 Nonanes ,2,4-TMB C 10 Decanes C 11 Undecanes C 12 Dodecanes C 13 Tridecanes C 14 Tetradecanes C 15 Pentadecanes C 16 Hexadecanes C 17 Heptdecanes C 18 Octadecanes C 19 Nonadecanes C 20 Eicosanes C 21 Heneicosanes C 22 Docosanes C 23 Tricosanes C 24 Tetracosanes C 25 Pentacosanes C 26 Hexacosanes C 27 Heptacosanes C 28 Octacosanes C 29 Nonacosanes C 30 Triacontanes C 31 Hentriacontanes C 32 Dotriacontanes C 33 Tritriacontanes C 34 Tetratriacontanes C 35 Penatriacontanes C 36 + Hexatriacontanes Plus Totals Note: 0.00 means < Table 15: Initial Composition of West Bukha Wellstream Development Plan (Subsurface) The development plan on the Omani side of the field involves the deepening of West Bukha-2 and the drilling of a second, high angle well close to the Iranian border, the wells being produced to a platform, and thence to the Bukha platform this is called (by the field owners) Phase I of the development. During this phase, field performance will be monitored to determine the need for future wells (Phase II and beyond). The platform will have space for 6 wells, and we believe an additional 2 wells will be drilled in Phase II; further drilling thereafter will depend on medium-term field performance. The wells will be equipped with the ability to selectively produce from one formation or both there is no final decision yet on which option to run with. 89

92 RPS Energy Heritage Oil Competent Persons Report Impact of Operations on the Iranian Side and Unitisation. Following the drilling of the last Iranian well in the field (Henjam-2 in 2006), there has been no further activity. However, NIOC representatives have placed in the public domain, comments and suggestions concerning the development as follows: The field is jointly owned by Iran and Oman; 85 per cent. of the produced oil should belong to Iran depending on well locations. Other reports from the NIOC in Iran have provided details of an imminent development of the Henjam side as follows (published in a late 2007 article (5) ): It is planned to drill two wells and workover and compete well #2 as soon as possible. A 16, 40-km pipeline is to be constructed from Henjam to Gheshm Island. Drilling operations would start soon with one rig, with a second rig would be provided in the near future; Gas would be transferred to Gheshm. The oil would be separated on Gheshm Island and then would be sent via 25-km pipeline to the 112-km line going to Siri Island. It was said that equipment and materials were en route to the field zone. We believe that negotiations on joint development continue (this was confirmed by the West Bukha Operator at the September, 2007 OCM). We believe and have assumed that: The Operator, Rak, has permission from the Omani authorities to proceed with the development of the Omani side of the field (6) The sides will eventually agree on a unitisation or a production split This split will be more like our distribution of STOIIP, namely: 62.5:37.5 Iran: Oman; Iran will eventually drill up its side the field or, if it does not, it will still receive some form of compensation. The stretch target for first oil is 3Q, 2008; we have assumed for our evaluation a range of start dates between 2Q 2008 in the p10 case and 1Q 2009 in the p90 case Recovery Mechanisms The dominant recovery mechanisms in the reservoir are likely to be solution gas drive, fracture compaction, oil expansion and a degree of aquifer influx. Such reservoirs are not good candidates for water or gas injection because of the presence of pervasive fractures. RPS has used a range of technical recovery factors ( RF s) ranging from 10 to 25 per cent. to reflect the recovery from similar reservoirs under natural depletion in the region, with slightly better RFs. RPS is aware of reservoirs in time-equivalent formations in the region that have recovered less than 10 per cent. over several decades, but these were developed inefficiently and intermittently using only vertical wells Production Profiles The Operator commissioned a consultant to generate the profiles for its development plan using numerical reservoir simulation (7). We have examined this work in detail and find that the p90 profile, in particular the initial sustainable rate, is not supportable, as the location of the second well and the reservoir quality at that location are as yet unknown, and the variation in same can be great. In addition, reservoir simulation not corroborated by sustained production, and with limited data to constrain the model, is not wholly unique or dependable. To mitigate this risk, the Operator has studied fracturing and facies to optimise the location of the second well, but the deliverability (particularly long-term) of future wells remains uncertain. (5) Source: NIOC website article, 27 November 2007; this could of course be propaganda or posturing (6) There is precedent in the region, such as the giant North Field (Qatar) and South Pars field (Iran), which straddles the Iran/ Qatar border and has been developed independently by each country. (7) The latest SPE et al. guidelines & auditing standards state that simulation is an accepted method of estimating future production; however the validity of same is enhanced when there is sufficient production history to validate the model, and estimators must have an understanding of the limitations of simulation. 90

93 RPS Energy Heritage Oil Competent Persons Report Estimation of the Product Streams In addition to the above estimation of the black oil production, reserves estimates of C 3, C 4, dry gas, and condensate are required for completeness. To achieve this, we have used an Equation of State ( EoS ) PVT simulator to perform an equilibrium flash on the expected wellstream composition above and below the bubble point. The following yields per stb of black oil were obtained from this exercise (Table 16): Above Bubble Point Average Below Bubble Point Thamama Dry gas ft ft 3 C stb stb C stb stb LPG total stb stb Condensate stb stb Mishrif Dry gas ft ft 3 C stb stb C stb stb LPG total stb stb Condensate stb stb Table 16: Estimated Product Yields from West Bukha Wellstream These were used in combination with black oil production, reserves-weighted between the Mishrif and Thamama Formations. The dry gas stream was reduced to account for losses, pilot, fuel and downtime. These complicated calculations are needless to say just qualitative, and it will take several months of sustained, stable production to ratify the yields, which will also vary as a function of which formations are open. Developmental Risk At this pre-production stage, there are developmental risks, in addition to the obvious reservoir risks. The risks, which may impact the timing and amount of future cash flow all standard at this stage of a development and by no means specific to West Bukha include but may not be limited to the following: The timing and efficient functioning of the facilities; The timing and results of the well operations; The timing, location and results of the second development well; and Specific to West Bukha: any retrospective adjustment to produced volumes or cashflow as a result of a later agreement between the Iranians and Omanis. 91

94 RPS Energy Heritage Oil Competent Persons Report The production profiles for the 1P, 2P and 3P cases are shown in Figure 11 to Figure 13. 8, Oil, Propane, Butane & Condensate Annual Average Rate (stb/d) 7,000 6,000 5,000 4,000 3,000 2,000 1,000 25, Black Oil Propane Butane Condensate Sales Gas Figure 11: 1P Production Profile for West Bukha Sales Gas Rate (MMscf/d) 26FEB , Liquid Rates (stb/d) 15,000 10, Gas Rate (MMscf/d) 5, NB "2008" is only the period 1/11/08 to 31/12/ Black Oil (stb/d) Propane (stb/d) Butane (stb/d) Condensate (stb/d) Sales Gas (MMscf/d) Figure 12: 2P Production Profile for West Bukha FEB

95 RPS Energy Heritage Oil Competent Persons Report 30, , , Liquid Rates (stb/d) 15,000 10,000 5, NB "2008" is only the period 1/09/08 to 31/12/ Black Oil (stb/d) Propane. C3H8 (stb/d) Butane, C4H10 (stb/d) Condensate (stb/d) Figure 13: 3P Production Profile for West Bukha Sales Gas (MMscf/d) Economically recoverable reserves are discussed in the economics section, Section 7, below Gas Rate (MMscf/d) 27FEB Facilities & Costs As discussed above, RPS has assumed that West Bukha will come on stream in 1Q 2009 by means of a wellhead tower tied back to Bukha central. West Bukha has several liquid streams. Condensate will be sold to existing long term customers, with LPG and Butane being sold to local markets. Modifications to Bukha and the RAKGAS plant will be required but these are assumed not to be significant in comparison to the overall development cost. Total costs for the platform, tie-back and modifications to RAKGAS are estimated to be US$96 MM including some contingency. Three new deep production wells are required in the p50 case together with costs to deepen the West Bukha 2 appraisal well. RPS understands that the West Bukha-3 well will be drilled during 2008 after installation of the wellhead tower at a cost estimated at US$59 MM. Deepening the West Bukha-2 well is expected to cost US$30 MM. Operating costs for the West Bukha offshore facilities are expected to be minimal with an annual field Opex of US$2.5 MM plus the cost of operating the existing facilities which has been running at US$5 MM per annum. RPS has assumed periodical workover would be required and workover costs are included at US$4 MM every three years. There is a General and Administrative (G&A) cost of US$1.5 MM per annum assumed during field life. Abandonment liability for the West Bukha facilities including the removal of the surface facilities and plugging and abandoning wells reverts to the government. 4. ZAPADNO CHUMPASSKOYE The Zapadno Chumpasskoye Licence is located in the West Siberian Basin in the Khanty-Mansyisk Province of Russia. Six producing oil fields operated by Lukoil surround Zapadno Chumpasskoye. The nearest city is Langepass located 8 km to the east. Heritage acquired the field in November 2005 from TNK-BP and created a subsidiary, ChumpassNefteDobycha (CND), to operate and develop the field. Earlier work on the field included 9 exploration wells and several km of 2D seismic. In 2006 CND prepared the necessary approvals to commence work on the field, including gathering 202 km of new seismic, constructing a road, separation facility and drilling cluster to conduct further appraisal drilling and commence pilot operation. An existing well was re-entered and three new wells have been drilled. 93

96 RPS Energy Heritage Oil Competent Persons Report 4.1. Data Available Data from the surrounding fields was sparse because competitor data is proprietary. A variety of data was available for this review. Seismic data coverage (2006 survey and the older data) comprising 2D lines shot at fairly wide spacing. A number of Russian drilled wells with Russian style wireline logs limited to SP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. Two new wells have been drilled in 2007 (P3 and P2) and a third (P4) was finishing drilling when this report was being prepared. New wells drilled in 2007 by Heritage have modern western-style logs. DST data from new wells, summaries of reservoir simulation studies and production data from Wells 226 and P3 were provided Geology Regional Setting The Upper Jurassic sequence in the Zapadno Chumpasskoye Licence is understood to comprise a sequence of shallow marine clastics, which are widely deposited in the West Siberian Basin. The Upper Jurassic is some 60 to 70 meters thick and includes a lower section of claystones and upper sand sequence interbedded with siltstones and claystones. The Upper Jurassic in the area is overlain by the Bazhenov Formation, a 20 to 25 metre thick bituminous shale which is both the source and the cap rock for the reservoir. The six fields surrounding Zapadno Chumpasskoye are also reported to be producing from the Upper Jurassic Zapadno Chumpasskoye Field The data from Russian drilled wells available for evaluating net sand, net pay and fluid contact is limited to SP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. These are low resolution tools and the resistivity logs are unfocused. There are no porosity logs. The SP logs were normalised to enable a consistent comparison of sand quality between wells. Net sand was initially picked at a typical VCL cut-off 50 per cent. However, to compensate for the low resolution of the SP and the presence of thin beds, a higher VCL cut-off was accepted for the thinner layers (i.e. thickness less than 5m). The Russian lateral logs were reviewed for evidence of hydrocarbons in the wells and to determine the fluid contacts. The log response is asymmetrical and only a qualitative interpretation was possible. The shallower hydrocarbon bearing sands were found to indicate resistivities approaching and exceeding 40 Ohmm, whereas the deeper formation closer to the hydrocarbon-water contact tended towards 15 Ohmm. The resistivity measurements in some of the thinner sands were uncertain due to poor log resolution. New wells drilled in 2007 by Heritage have modern western-style logs. Prior to the new wells, Heritage presented a correlation of the upper part of an Upper Jurassic clastic sequence based on lithostratigraphy (no biostratigraphic data is available). Two sandstone intervals (the Upper and Lower J 1 Sandstones) were identified in the upper part of the sequence and correlated between most of the wells using the SP logs. These occur below the base of the low conductivity zone, equating to the Bazhenov shale which is the seal and source rock for the Jurassic reservoirs. The correlation has been revised based on data from the 2007 wells and additional older well data that has become available to Heritage. The revised interpretation suggests that the Upper J 1 Sand is very localised and no volumes are now assigned to this sand. Well spacing is large in this licence (between 2 and 7 km) and lateral variations in sand content and quality, plus sand pinch-outs and amalgamations are likely to occur within such distances. The model of pinch-out of the Upper Sand on to the high in the south is a reasonable interpretation of the logs and is supported by evidence from well P2. Seismic data quality in this licence is of moderate quality; however the frequency content of the data at reservoir level is insufficient to define the reservoir thickness. Effectively the only presently perceived use for these data is to define the structure at the top of the reservoir sequence which is seen to be a simple north-westerly dipping surface. Heritage provided depth structure maps at Top Upper Sand levels. Seismic data have been reviewed; seismic survey data coverage comprises 2D lines shot at fairly wide spacing. No faults are shown on the 94

97 RPS Energy Heritage Oil Competent Persons Report maps, but it is expected that faults will cut the sequence and offset the relatively thin (generally less than 10m) sands. Due to the stratigraphic nature of the trap, seismic interpretation is not regarded as critical to the volumetric evaluation. Heritage s Net Oil Pay thickness maps were reviewed and modified as appropriate including an estimate of the pinch out edge to the south (the exact position of this pinch out cannot be precisely located on the seismic). No definitive OWC has been identified, but possible fluid contacts were picked at 2,702m TVDSS (deepest dry oil production in Well 226), 2,724m TVDSS (ODT in Well 943) and 2,756m TVDSS (possible ODT in Well 100). The Net Oil Pay thicknesses above each of these contacts were hand contoured, digitised and Net Pay Rock Volumes calculated. The p50 Net Pay Map is shown in Figure 14. Figure 14: Lower J 1 Sand RPS Net Pay Map (p50 Case) 21FEB Petrophysics RPS undertook an independent petrophysical review of wells P2ST and P3. The S w values interpreted from western logs in Well P3 were higher than expected. As a result a detailed review of core and water analysis data derived from core taken from Well P3 was undertaken. These data provided a basis for calibrating the logs from P2 ST and P3. Core was taken from Well P3 where a water base mud was tagged with a fluorescent dye. The core barrel contained a glass fibre inner barrel that was filled with depolarized mineral oil. To obtain the background reading of fluorescent dye concentration, the tagged mud was sampled regularly during coring. However, no fluorescence was detected from the water extracted from the 95

98 RPS Energy Heritage Oil Competent Persons Report core and it is therefore considered that the core did not suffer filtrate invasion in the volumes sampled for water extraction, and no invasion corrections were applied. Values of R w were taken from the data supplied by Heritage where residual water was extracted from the core and its resistivity determined. The average value from 8 samples reported was Ohmm at 20 C with standard deviation of the mean of Ohmm. Arps equation (8) was used to convert this to reservoir temperatures. This resistivity represents an equivalent NaCl concentration of approximately 24,000 ppm. The result is in line with a previously reported salinity from well No. 14 which gave a value of 22,105 ppm. The ambient Archie Cementation exponent m and Saturation exponent n derived from P3 core were 1.77 and 1.85, respectively. A produced water analysis was supplied by Heritage which was obtained by centrifuging an oil sample from co-mingled production from Wells S226 and P3. The chemical analysis obtained a salinity of 49,454 ppm, which has an estimated R w of Ohmm at 20 C. Because of the ambiguity in the results from the brine analyses, the Ohmm R w at 20 C was used to calculate saturations at the p90 level, and the Ohmm R w at 20 was used to calculate saturations at the p50 level. In the case of well P2ST, VSH was derived from the lower value from the density neutron cross plot method and a linear Gamma Ray VSH method derived from the Potassium and Thorium component of the gamma ray count. Parameters are presented in Table 1 in the Appendix. For well P3, shale volume was determined from a density neutron crossplot using the parameters presented in Table 2 in the Appendix. For well P2ST, porosity was derived using the density neutron crossplot method In the case of well P3, porosity was derived for the LCa and LCb zones using the density neutron crossplot method. Porosity in LCc was derived from the density log. The parameters used in calculating porosity for both wells are presented in Tables 1 & 2 in the Appendix. For both wells, total water saturation was calculated using the Archie equation (9). Effective water saturation was derived using the shaley sand Indonesia Equation of Poupon and Leveaux (10). A CPI (for the p50 saturation case) from Well P3 is shown in Figure 15. Owing to the silty and thin bedded nature of parts of the reservoir, it is possible that thin beds are not being resolved fully by tool responses, and that the results of the interpretations have been influenced by smoothed tool responses. A p50 case for water saturation has used an R w of Ohm at 20 C. An R w of Ohm at 20 C has been used to construct saturations for the p90 case. (8) Arps, J.J. (1953) The Effect of Temperature on the Density and Electrical Resistivity of Sodium Chloride Solutions Petroleum Transactions, AIME, Vol 198, (9) Archie, G.E. The Electrical Resistivity Log as an Aid in Determining Some Reservoir Characteristics. Petroleum Transactions of the AIME 146 (1942). (10) A. Poupon, J, Leveaux Evaluation of Water Saturation in Shaly Formations. SPWLA 12 th Annual Logging Symposium, May

99 RPS Energy Heritage Oil Competent Persons Report 21FEB Figure 15: CPI for Well P3 over Reservoir Interval for p50 Saturation Case 4.3. In Place Volumes Porosity, saturation and formation volume factor ranges were estimated based on the RPS review of petrophysical data from wells P2ST and P3 and the Operator s interpretation of the older Russian wells, based on their regional knowledge and assumptions that the reservoirs are analogous with those in the surrounding area. As a result of the differences in interpreted S w a broad range of S w was used in the volumetric calculations. Input parameters are shown in Table 17. Low Mid High Net Pay Rock Volume (MM m 3 ) Porosity (%) Oil Saturation (%) B oi (rb/stb) Table 17: Lower J 1 Sand Input Parameters STOIIP has been estimated probabilistically and is summarised Table 18 below. STOIIP (MMstb) p90 p50 p Table 18: Zapadno Chumpasskoye, Lower J 1 Sand, STOIIP Estimates (MMstb) 97

100 RPS Energy Heritage Oil Competent Persons Report 4.4. Petroleum Engineering Reservoir Fluid Properties The Lower J 1 Sand contains an undersaturated oil at an initial pressure and temperature of approximately 28 MPa (4,018 psia) and 83 C (181 F), respectively, at a depth of 2,750 m. The produced oil has a density of 834 kg m -3 (~38 API). The in-situ viscosity of the oil is likely to be 2-3 times that of water, and the bubble point of the reservoir oil is 1,320 psia (the implication of these factors is discussed below). The initial solution GOR (R si ) is 410 scf/stb, and the initial formation volume factor (B oi ) is 1.25 rb/stb Well Performance & Deliverability Two wells have been tested and produced on the acreage, namely 226 and P3. Their production history is shown in Figure 16 and Figure 17 below. The highest rate achieved by each well is stb/d and stb/d, respectively. Figure 16: Well 226 Production History 27FEB

101 RPS Energy Heritage Oil Competent Persons Report Figure 17: Well P3 Production History 27FEB Whist decline has clearly set in, it is very early in the producing life of the well and the field, and any decline will change when water injection commences and downhole pumps are installed. The declines observed so far seem to be hyperbolic in nature, as might be expected under purely natural decline, although well P3 has been damaged as a result of killing the well to retrieve a packer during which the tubing fell downhole. This resulted in a bullhead kill. Permeability varies from 5 to 25 md across the block and the initial well rates that will likely be encountered are 300 to 600 stb/d. As one of the measures to improve drilling performance and improve well performance by minimizing well impairment, Heritage intends to replace the current rig and contractor in order to improve drilling procedures and avoid damaging the future wells the new rig and contractor will arrive some time after the currently active well (P4) Development Plan (Subsurface) In May 27, 2007, the Russian authorities approved phase 1 of the development, consisting of reservoir studies and early wells to establish the efficacy of a full field development ( FFD ) using an inverted 5-spot pattern. The initial approval covers the drilling of up to 53 wells including 13 injection wells. That approval permits ongoing development and production activities during which it is expected that in 2010 the Company will present an evaluation of the results obtained and present its plan for further development. Whilst the FFD has not yet been approved we believe it is reasonably certain that such approval will be forthcoming. The long-term development plan is to drill a number of inverted 5-spot patterns, consisting of injectors inside a square with a producer ion each corner of this square. Figure 18 illustrates how several of these patterns might look (source: Heritage). 99

102 RPS Energy Heritage Oil Competent Persons Report Figure 18: 27FEB Illustration of Inverted Five-spot Patterns at Zapadno Chumpasskoye The well count will be built up over the next few years, The current plan to maintain reservoir pressure is to inject water injection at high voidage replacement ratios ( VRR s) (in excess of 1) to re-pressure the reservoir. Wells will be drilled from well pads, with maximum step-out from the surface location of 1.5 km Recovery Mechanisms Whist under natural depletion, wells will produce through oil expansion with perhaps some aquifer influx. It is unlikely that reservoir pressure will reach the bubble point at any point in the reservoir before water injection commences, so solution gas drive will not be developed. Once water injection commences, planned at VRR in excess of 1, the unfavourable mobility ratio will cause some of the water to create viscous fingers through the oil leg. Consideration is being given to the optimum reservoir pressure for flooding. 100

103 RPS Energy Heritage Oil Competent Persons Report Production Profiles The Company has performed sector and a P90 low case full field simulation studies, and the key output from the latter is shown pictorially in Figure 19 to Figure 21. Figure 19: Oil Rate & Cumulative from Full Field Simulation 22FEB Figure 20: 22FEB Water Injection Rate & Cumulative from Full Field Simulation 101

104 RPS Energy Heritage Oil Competent Persons Report Figure 21: Average Reservoir Pressure from Full Field Simulation 22FEB Heritage has used a downside geological scenario in the simulator, as is necessary for the development plan submitted to the authorities. The above output shows oil rate building up to some 1,200 m 3 /d (7,548 stb/d) following water injection which builds to a peak rate of 2,800 m 3 /d (17,611 bbl/d). This rate eventually far exceeds voidage and the reservoir is re-pressurised (Figure 21), although in practice it is not necessary to exceed initial reservoir pressure. This case consists of a total of 49 producers, and 32 injectors, as shown below in the drilling schedule for the Company s p90 and p50 cases p90 New Producers Cumulative Producers New Injectors Cumulative Injectors Total in Year p50 New Producers Cumulative Producers New Injectors Cumulative Injectors Total in Year Table 19: The p90 and p50 Drilling Schedule for Zapadno Chumpasskoye The simulation work is reasonable, but of course is not matched to a sustained period of history (and is thus less reliable than it will be once more performance data become available). The two producers have (to the effective date) produced some MMstb. Some of the rates achieved by wells in the simulator surpass those rates seen in the field to date, albeit in just two wells. We have used the above drilling schedule, the rate build-up from the simulator, but reduced rates to construct a production profile for our 1P case; we have also allowed for downtime that is likely to occur to well, pump, facility, and pipeline availability. 102

105 RPS Energy Heritage Oil Competent Persons Report Our p50 case is scaled to honour potentially higher initial well rates and an improved recovery factor, and also the p50 scenario drilling schedule (a total of 84 producers and 46 injectors). The Company has not yet created a p10 scenario. To do this, we have used the area of the field inside the 1 m net pay contour to determine the well count, an assumption of improved well rates (600 stb/d) and recovery factor. The resulting profiles are shown in Figure 22 to Figure 24 (note: in all these figures, the 2007 rate is the average for the period 1 October to 31 December, 2007). 7,000 6,000 5,000 Gross Oil Rate (stb/d) 4,000 3,000 2,000 1, FEB Figure 22: 1P Production Profile for Zapadno Chumpasskoye 18,000 16,000 14,000 Gross Oil Rate (stb/d) 12,000 10,000 8,000 6,000 4,000 2, Figure 23: P Production Profile for Zapadno Chumpasskoye 27FEB

106 RPS Energy Heritage Oil Competent Persons Report 50,000 45,000 40,000 35,000 Gross Oil Rate (stb/d) 30,000 25,000 20,000 15,000 10,000 5, FEB Figure 24: 3P Production Profile for Zapadno Chumpasskoye The summary output from the three RPS cases, combined with the STOIIP estimates from 4.3, above is given in Table 20: 1P 2P 3P STOIIP (MMstb) URR (11) (MMstb) URR/well (MMstb) Table 20: Summary of Results for Zapadno Chumpasskoye (12) This range of outcomes is reasonable for the range of reservoir quality expected to be encountered in the block. Developmental Risk We have categorised these volumes as reserves despite the absence of formal approval of the FFD as there is 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 (as required under SPE et al. guidelines). At this pre-production stage, there are developmental risks, in addition to the obvious reservoir risks. These risks, which may impact the timing and amount of future cash flow all standard at this stage of a development and by no means specific to for Zapadno Chumpasskoye include but may not be limited to the following: The timing and any conditions of the formal approval by the Russian authorities of the development plan efficient functioning of the facilities; The timing and operation of a replacement drilling rig; we note that Heritage is in receipt of a commercial tender for a superior rig; The timing, location and results of the numerous development wells to be drilled; (11) Ultimately Recoverable Resources this may not be the finally quoted reserves (see economics section) if economic analysis terminates the profile before this cumulative is reached. (12) There are no commercial gas reserves as all gas is and will be used in the field for fuel, flare pilot and so on, with the remainder flared. We are not aware of any limitations to the volume of gas that can be flared. 104

107 RPS Energy Heritage Oil Competent Persons Report The installation and commissioning of new facilities of appropriate size for the production, processing and transportation of the produced oil; (Heritage advise that CND s plan is currently in front of regulators for their approval) The raising of sufficient capital funds to cover these development costs Facilities and Costs Commercial production commenced in 2007 on a small scale from two wells. The current plan is to drill up to 84 producers in the p50 case along with 46 Water Injection wells for reservoir support. Two drilling rigs will eventually be required with a planned 16 wells in years 2010 to The p50 Case is expected to produce over 60 MMstb peaking at about 16,000 bopd in Capital expenditure (facilities costs) for the most likely case is estimated at US$180 MM including a 20 per cent. contingency. The 130 wells will be drilled at a cost of average US$2 MM each. In the p10 case, with over 200 wells. RPS has assumed an additional drilling rig is required from Production would be over 170 MMstb with a capital expenditure of over US$300 MM. Operating costs are assumed to be US$12 MM per annum during the plateau years plus a further US$1.5 MM per annum for G&A. 5. UGANDA BLOCKS 1 & 3A 5.1. Overview Ugandan Block 3A is located in the south of Lake Albert and covers the southern part of the Ugandan side of Lake Albert. Block 1 is located on land to the north of Lake Albert. Lake Albert is a largest lake in the northern sector of the Western Rift. The lake surface is approximately 618 m above sea level and its rifted margins are more than 2,200 m above sea level in the west and more than 1,300 m in the east. Here, the graben has an average width of 45 km and is approximately 190 km long. Whilst many of the Western Rift segments contain deepwater lakes, such as Lake Malawi (750 m) and Lake Tanganyika (1,500 m), Lake Albert has relatively shallow water depths (approximate maximum of 60 m) but is believed to have similar sediment thicknesses as the other lakes. The Albert Basin is the most petroleum prospective area in Uganda and is a classical active rift basin of the East African Rift system Data Available The seismic database in Block 3A comprises 16 widely spaced 2D seismic lines of varying vintages The data quality in the northern half of the block is fair with well defined reflections down to the base of the Tertiary basin fill. To the south of the block the regional data becomes increasingly poor and mapping of the deeper levels is particularly difficult. A 3D survey also exists over the Kingfisher discovery covering 450 sq km along the south eastern lake shore, data quality is reasonable. Shallow data at Kingfisher lose coherency but this is above the zones of interest in the wells. Well data from 3 wells; Kingfisher-1, Kingfisher-1A and Kingfisher-1B were made available. Full log suites were made available for these wells as well as geological and test data. Block 1 is currently covered by 17 2D seismic lines across the southern portion of the block. Data quality is generally very good with retention of amplitudes, coherent reflector packages and fairly crisp fault terminations. As noted above, seismic acquisition in Blocks 1 and 3A is not due for completion until March Much of the area outside the 3D seismic in Block 3A will be covered by additional infill 2D lines and data will be available for the northern part of Block 1A. Tullow has been exploring a fault terrace in Block 2, to the north of Heritage s Block 3A and has a number of reported discoveries but RPS has no access to data from these wells. 105

108 RPS Energy Heritage Oil Competent Persons Report 5.3. Geological Setting The following discussion of the geological setting is based on RPS regional experience in the rift system. The Albert Basin system is part of the western limb of the East African Rift System. It is segmented along its length into individual, asymmetric basins, many of which contain lakes. Lake Albert is in the northern sector which trends from NNE to SSE. The rift is bordered on both sides by steeply dipping normal fault systems with cumulative heaves of up to 10 km, and uplifted rift flanks. The main structural components of the Albert Basin are the Albert Nile, Lake Albert, Semliki valley, Lake George and Lake Edward basins, changing progressively in trend from NNE to SSW to N-S, towards the south. The major tectonic stresses in the Albert Basin are extensional although there is evidence of compression. Inversion and compressional anticlines interpreted from public domain seismic data reveal these compressional episodes and probably represent localised inversion taking place within the rifting process due to oblique extension. The western border fault is a more steeply dipping normal fault than the eastern border fault with steeper uplifted flanks. Magnetic and gravity data suggest there are two main sub-basins separated by a basement high, which is a possible accommodation zone/transfer zone that formed along the NE-SW trending eastern border faults. In general, the stratigraphic sequence in the Albert Basin is divided into two mega sequences, Pre-rift and Syn-rift. The pre-rift sequence is predominantly composed of Pre-Cambrian basement rocks that are exposed on the rift flank and shoulder of the Albert Basin. It predominantly consists of meta-sediments to high-grade metamorphic rocks, mainly comprising gneisses, granitic gneisses and quartzites. The sequence is unconformably overlain by Early Tertiary sediments in many parts of the graben. However, there is also a strong possibility that the Tertiary sediments overlay Mesozoic sediments. The syn-rift sequence contains thick fluvio-lacustrine and lacustrine sediments of Cenozoic age, possibly ranging from Palaeogene?/Early Miocene to Recent. Oil is believed to be sourced from organic shales deposited in a lacustrine environment, where organic rich shales are concentrated. Oil seeps occur along the Ugandan shore of Lake Albert. More than 15 confirmed oil seeps are reported, with five seeps sampled in the Kibuku, Paraa, Kibiro, Hohwa and Kabyosi area. Sedimentation patterns in the Albert Basin are believed to be typical of a rift system with coarse deposits, in settings ranging from alluvial to deep water fans, forming narrow depositional belts in the hanging wall of major fault systems. The oldest syn-rift sedimentary units are coarse grained fluvial-deltaic sands. The coarse-grained basal syn-rift sequence passes upwards and laterally into a shale dominated sequence marking the deep lacustrine phase, which can provide important seals and source rocks. Large rift bounding faults control the location and bathymetry of most rift lakes. Once extension stops there is no mechanism for preserving the water depth and sediments begin to fill the basin to base level. In a continental rift this fill tends to be coarse grained fluvio-deltaic deposits that prograde over lacustrine sediments. The basin fill within the Albert Basin consists of Miocene to Pliocene age sediments capped by an approximate 200 m thick layer of Pleistocene alluvium. The predominant facies within the graben is lacustrine and marginal lacustrine siliciclastics and thick sequences of stacked fluvial channels. Fluviodeltaic sandstones may be thick and have good porosity. Interbedded shales, particularly where they correspond with lake high-stands are likely to be relatively thick and continuous, thus forming good regional seals. Good seismic reflection continuity within these packages attest to the good seal potential for these units. Tullow has been exploring a fault terrace north of Heritage s Block 3A and has a number of reported discoveries. Block 1 lies to the north of Lake Albert and from gravity maps appears to contain two sub-basins. The northern sub-basin trends in almost N-S and is separated from the NNE-SSW trending southern sub-basin by basement structural highs. The Pakwach Basin is a small half graben, which has a NNE-SSW orientation and is separated from main Albert Basin by a basement high. The basin is probably filled by fluviolacustrine and lacustrine sediments of Palaeogene?/Early Miocene to Pliocene age and alluvial plain Recent sediments. Two live seeps on the Victoria Nile near Paraa have been confirmed by oil freely bubbling onto the surface of the river. The presence of the oil seep indicates that the lacustrine shales are capable of generating oil, however its presence also suggests a risk of seal capacity. However, since only this and possibly one other seep has been identified in the area, the presence of the seep could simply be due to the fact that basins 106

109 RPS Energy Heritage Oil Competent Persons Report may not seal perfectly. The presence of seeps in Block 3 and in Block 2, close to existing discoveries, also support this hypothesis. The sub-basins and basement structural highs are prospective. There is, however, a risk that traps will be under-filled because of a possibly restricted source kitchen area in the Pakwach sub-basin. However, the prospects mapped in the southern part of this block should receive their oil from the Albert Basin via a good migration route Geology & Geophysics Kingfisher 1 The Kingfisher-1 well encountered a stacked series of sands and shales in the Pleistocene (Figure 25) and confirmed the presence of hydrocarbons in Block 3A. The vertical well and the sidetrack, Kingfisher 1A, both flowed hydrocarbons to surface from thin Late Miocene Pliocene sands. Kingfisher-1 tested a locally developed Early Pliocene (zone P2a) sand (13). Kingfisher-1A penetrated a water bearing P2a sand. However, Kingfisher-1A also tested oil from three separate sands in Late Miocene Early Pliocene P1/M6 cycle. Figure 25: Seismic Section through Kingfisher 1 Well 22FEB The Early Pliocene P2a sand tested in Kingfisher-1 is 12m thick. Kingfisher-1A penetrated three oil bearing sands within a 100m interval spanning the Miocene-Pliocene boundary at between 1,520 and 1,630 m TVDSS (Figure 26). These sands vary in thickness from 10 to 30 m. No water contacts were seen in any sands (13) Heritage stratigraphic nomenclature 107

110 RPS Energy Heritage Oil Competent Persons Report Figure 26: Reservoir Section in Kingfisher 1A 22FEB Source: Heritage The Kingfisher structure is a 3-way dip closure against the southern basin-bounding fault (Figure 27). The maximum areal closure is approximately 45 sq km. A deeper, probably Miocene basal sand, was the primary target of the well but the vertical well and first sidetrack encountered basement before reaching the primary target. A second sidetrack, which kicked off below the tested zones, was abandoned due to mechanical problems before reaching the Early Miocene target. Figure 27: RPS Cycle P1/M6 Depth Map, Block 3A 22FEB

111 RPS Energy Heritage Oil Competent Persons Report Mapping Heritage has mapped 4 horizons that have been reviewed and modified by RPS: Kingfisher P1/M6 interpretation of this unit is fairly robust over the 3D area. Seismic data quality drops around the faults in Kingfisher but deeper units show the general trend of the data. RPS has reinterpreted the area and modified the fault interpretation in the area of Kingfisher North and Pelican Kingfisher basal sand Interpretation of this unit is fairly robust over the Kingfisher 3D. Again, RPS has modified the fault interpretation in the area around Kingfisher North and Pelican Pliocene Light Blue Interpretation of this unit is good over the area mapped, although more faults exist than those interpreted by Heritage G: Near Top Zone 2 Seismic quality around the leads is very poor, consequently fault and horizon interpretation is open to question. Structures formed are caused by slight inflections in the interpretation around faults that may be seismic artefacts Prospectivity In addition to Kingfisher, Heritage has identified two further prospects along the basin bounding fault: Kingfisher North and Pelican. RPS has further separated the Pelican structure into three segments; Pelican Main, Pelican North and Pelican Shallow. The eastern area of the Pelican prospect is in a complex structural zone where the basin bounding fault is met by a parallel intra-basinal fault. The Pelican North and Shallow prospects are separated by significant vertical offset from the main Pelican prospect. A further prospect, Pelican West, is also a three-way dip structure but bounds the intra-basinal fault that converges with the main basin-bounding fault at Pelican. Heritage has identified a further three leads from 2D seismic data. These leads are broad, shallow anticlines and 3 way dip closures against intra-basinal faults. Each prospect and lead in Block 3A has dual targets in the Pliocene and Miocene. Heritage has used time structure maps to determine the extent of prospects and a simplified area-thickness approach has been used to calculate GRV. RPS has re-gridded their modified TWT horizons and created depth maps using a simple depth conversion using average velocities calculated from the time-depth relationship seen at Kingfisher-1. Block 1 lies at the Northern end of the Albert Basin where the Nile exits Lake Albert. There is no well control in the block. The block lies updip of the Lake Albert source kitchen, and is at the focal point of potential hydrocarbon migration from the basin depocentre. Heritage has identified four very shallow (less than 600 m) and potentially very large prospects in the area of existing seismic coverage in Block 1. These are named Buffalo, Crocodile, Giraffe and Hartebeest (Figure 28). 109

112 RPS Energy Heritage Oil Competent Persons Report Figure 28: RPS Top Reservoir Depth Map, Block 1 22FEB The maximum size of the structures in Block 1 range from 5 to 69 sq km. Heritage mapping is based on a strong reflector which they interpret, based on seismic facies, to be the top of a sandy sequence. The interpretation of this unit is very robust as the seismic quality is very good. Heritage has identified amplitude anomalies at the crest of structures throughout the block which could be indicative of hydrocarbon fill although the anomalies do not cover the entire area of the larger prospects. The concern that any oil might be biodegraded due to the very shallow reservoir depth is partly allayed by the presence of relatively light oil in the Paraa oil seep (Section 5.3). As in Block 3A, Heritage has used time structure maps to determine the extent of prospects and areas for volumes. RPS has re-gridded the mapped horizons and depth converted them using average velocities calculated from the time-depth relationship seen at Kingfisher-1. It is stressed that prior to the completion of the ongoing seismic programmes, large areas of both blocks, particularly the north of Block 1A are still relatively unexplored, although high resolution satellite data is understood to show the presence of some potentially interesting structures Volumetrics RPS has used area-depth curves calculated from the RPS depth maps which were produced by RPS for each prospect at each reservoir horizon. RPS applied an uncertainty on possible leak point/spill points to the prospects. For the P1/M6 cycle an appropriate range of gross reservoir thickness was taken from the Kingfisher 1A well and a stacking factor of three was applied to calculate the volume in the Kingfisher discovery and the Kingfisher North prospect. For other P1/M6 prospects a range of stacking factors between 2 and 4 was applied as there is uncertainty over continuity of the reservoir sands. The basal sands are interpreted to be thicker alluvial to fluvial early syn-rift sediments. Consequently, RPS has assumed a greater range of thicknesses than the younger Pliocene sands. RPS undertook an independent petrophysical evaluation of the Kingfisher well. The results of this evaluation have been used to constrain the range of N:G, porosity and S w values used in the Pliocene prospects along the basin margin. Lower average porosities were assumed in the deeper Pliocene leads and the Miocene basal sands. 110