Heritage Oil Limited

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 CA4269283053. 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. CONTENTS

Page SUMMARY INFORMATION ...... 1 RISK FACTORS ...... 11 DIRECTORS, CORPORATE SECRETARY, SENIOR MANAGERS, REGISTERED OFFICE, DIRECTORS’ AND SENIOR MANAGERS’ BUSINESS ADDRESSES, HEAD OFFICE, U.K. OFFICE AND ADVISERS ...... 27 EXPECTED TIMETABLE OF PRINCIPAL EVENTS ...... 29 FORWARD-LOOKING STATEMENTS AND OTHER INFORMATION ...... 30 IMPORTANT INFORMATION ...... 32 PART I—INFORMATION ON THE GROUP ...... 33 PART II—DIRECTORS, MANAGEMENT AND CORPORATE GOVERNANCE ...... 58 PART III—TECHNICAL REPORT ...... 62 PART IV—SELECTED FINANCIAL INFORMATION ...... 132 PART V—OPERATING AND FINANCIAL REVIEW ...... 136 PART VI—CAPITALISATION AND INDEBTEDNESS ...... 168 PART VII—FINANCIAL INFORMATION ...... 169 A. FINANCIAL INFORMATION RELATING TO THE COMPANY ...... 169 B. AUDITED (AND UNAUDITED) FINANCIAL INFORMATION RELATING TOHOC...... 174 C. PRO FORMA FINANCIAL INFORMATION FOR THE COMPANY ...... 237 PART VIII—ILLUSTRATIVE PROJECTIONS OF THE GROUP ...... 240 PART IX—CORPORATE REORGANISATION ...... 246 PART X—ADDITIONAL INFORMATION ...... 249 PART XI—DEFINITIONS ...... 294 PART XII—GLOSSARY ...... 304

i 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 ...... 25.5 24.2 30.3 Probable Additional ...... 40.3 37.9 229.3 Total Proved Probable ...... 65.8 62.1 259.6 Total Proved Probable Possible ...... 171.5 163.9 824.1

1 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 2007.

4. 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 2005. 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 2004. 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 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 2005 2006 2006 2007 $$$$ (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 ...... 0.16 0.57 0.11 —

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 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 2005 2006 2006 2007 $$$$ (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 ...... — 914,558 — 4,200,909 69,973,627 89,443,027 89,458,028 149,053,091

Current assets Assets held for sale ...... — — 425,412 — Inventories ...... 251,915 98,921 211,510 79,768 Prepaid expenses ...... 219,222 531,273 515,899 340,402 Trade and other receivables ...... 1,318,450 9,839,506 664,953 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 80,346,535 146,773,873 138,127,373 217,823,275

Liabilities Current liabilities Trade and other payables ...... 4,438,649 12,715,381 9,396,651 15,781,606 Borrowings ...... 248,045 147,720 140,352 160,224 Liabilities of disposal group held for sale ..... — — 807,208 — 4,686,694 12,863,101 10,344,211 15,941,830

Non-current liabilities Borrowings ...... 7,520,438 63,124,843 62,512,234 144,918,765 Derivative financial liability ...... — 27,997,140 8,621,068 32,810,103 Provisions ...... 434,849 62,322 — 133,274 Liabilities of disposal group held for sale ..... — — 419,770 — 7,955,287 91,184,305 71,553,072 177,862,142 12,641,981 104,047,406 81,897,283 193,803,972 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 ...... 973,956 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 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 nine- month period ended 30 September 2006 prepared in accordance with IFRS and unaudited)

Year ended Nine-month periods 31 December ended 30 September 2005 2006 2006 2007 $$$$ (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) 482,954 308,481 701,730 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)

2004 2005 $$ 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 ...... 1.33 (0.18) Diluted ...... 1.31 (0.18)

5 Summary Consolidated Balance Sheets (at 31 December 2004 and 2005 prepared in accordance with Canadian GAAP and audited)

2004 2005 $$ 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 ...... 94,483 216,474 Prepaid expenses ...... 272,168 219,222 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 ...... — 248,045 6,397,247 4,686,694 Long-term debt ...... — 7,520,438 Asset retirement obligations ...... 328,553 434,849 Shareholders’ Equity: Share capital and warrants ...... 21,434,168 22,854,418 Contributed surplus ...... 24,421 517,209 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)

2004 2005 $$ Cash provided by operating activities ...... 1,866,009 697,123 Cash used in investing activities ...... (11,310,312) (16,184,349) Cash provided by financing activities ...... 604,953 9,020,147 Foreign exchange gains (losses) on cash held in foreign currency ...... 906,001 (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 8,583,321

6. CURRENT TRADING AND PROSPECTS The Company is well positioned to benefit from a series of exploration, appraisal and development drilling programmes in 2008. Drilling programmes in Blocks 3A and 1 are scheduled to commence in Uganda in 2008. An exploration well is also scheduled to commence drilling in the Miran licence in the KRI in the second half of 2008.

6 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 2008.

7. 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 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 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 non- core 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 2007.

11. 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 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 2008. 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 ...... 52 Chairman and Non-Executive Director Anthony Buckingham ...... 56 Chief Executive Officer Paul Atherton ...... 42 Chief Financial Officer Gregory Turnbull ...... 53 Non-Executive Director John McLeod ...... 61 Non-Executive Director General Sir Michael Wilkes ...... 67 Non-Executive Director

On Admission, in addition to the Board, the position of the Senior Manager will be:

Name Age Position Brian Smith ...... 55 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 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 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 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 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 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 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 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 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 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 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 2008. 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 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 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 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 2006. 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 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 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 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 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’ 28-30 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 Tetrault´ Company Registered Foreign Lawyers & Solicitors 2nd Floor 5 Old Bailey London EC4M 7BA United Kingdom Canadian Legal Advisers to the McCarthy Tetrault´ LLP Company Suite 3300 421 7th Avenue S.W. Calgary Alberta T2P 4K9 Canada

27 Jersey Legal Advisers to the Mourant du Feu & Jeune Company 22 Grenville Street St Helier Jersey JE4 8PX Channel Islands English Legal Advisers to the Linklaters LLP Sponsor One Silk Street London EC2Y 8HQ United Kingdom Canadian Legal Advisers to the Stikeman Elliott LLP Sponsor Dauntsey House 4B Frederick’s Place London EC2R 8AB United Kingdom Auditors and Reporting KPMG LLP U.K. Accountants of the Company 8 Salisbury Square London, EC4Y 8BB United Kingdom Auditors of HOC KPMG LLP Canada National Local Suite 3300 205-5th Avenue S.W. Commerce Court West Bow Valley Square II 199 Bay Street Calgary, Alberta Toronto, Ontario T2P 4K9 M5L 1B2 Canada Canada Registrars of the Company Computershare Investor Services (Channel Islands) Limited Ordnance House 31 Pier Road St Helier Jersey JE4 8PW Channel Islands Principal Bankers of the Royal Bank of Canada (Canada) Company Standard Bank (Europe) Bank of Scotland (Europe) Independent Petroleum RPS Energy Engineering Consultants to the Goldsworth House Company Denton Way Goldsworth Park Woking Surrey GU21 3LG United Kingdom Voting Trustee for the Special Computershare Trust Company Voting Share in the Company of Canada Suite 600 530 8th Avenue S.W. Calgary Alberta T2P 3S8 Canada

28 EXPECTED TIMETABLE OF PRINCIPAL EVENTS

Plan of Arrangement becomes effective and the Company becomes the ultimate holding company of the Group(1) ...... 31 March 2008 Admission and expected commencement of dealings in the Ordinary Shares on the London Stock Exchange ...... 8.00 am on 31 March 2008 Ordinary Shares credited to CREST accounts ...... 31 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 ...... 8.00 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 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 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 2007. 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 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.

IMPORTANT INFORMATION General 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 www.heritageoilcorp.com or www.heritageoilltd.com. 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 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 2008. 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 2008. 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 2006. 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 2007. 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 2007. 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 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 ...... 25.5 24.2 30.3 Probable Additional ...... 40.3 37.9 229.3 Total Proved + Probable ...... 65.8 62.1 259.6 Total Proved + Probable + Possible ...... 171.5 163.9 824.1

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 2007. 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 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 oil- bearing 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 2007. 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 2007. 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 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 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 1 39.5% Tullow DRC...... Block 2 39.5% 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. 3068-2 60% 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 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

226 3 2

0 10km

LEGEND

Heritage PSA

Fields

Oil Pipelines

Gas Pipelines

Exploration & Appraisal Well

14MAR200800541245

38 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 1997. 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 2007. 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 2005 2006 2006 2007 $$ $ $ (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 2005.

Production from the field commenced in 2007, and management estimate could increase to a peak of approximately 16,000 bopd in 2014. 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 2010.

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 ...... 23.1 23.1 17.5 Probable Additional ...... 37.4 37.4 209.1 Total Proved + Probable ...... 60.5 60.5 226.6 Total Proved + Probable + Possible ...... 161.4 161.4 762.2

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 2007. 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 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 m3 gas with current production of approximately 740,000 bopd and approximately 50 million m3/day gas. Current consumption is some 66,000 bopd and 2.4 million m3/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 m3 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

Qeshm Salakh Island Straits of Hormuz

BLOCK 8 West Bukha Field

Bukha Field

Mubarek Field Khor Khwair Processing Plant OMAN

Ras Al Khaimah LEGEND

Heritage PSA

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Gas Fields U.A.E Gas Condensate Field Oil & Gas Well

Dubai Pipelines

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International Border

0 100km OMAN 14MAR200800540808

40 The Group acquired a 10 per cent. interest in Block 8 offshore of Oman in 1996. 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 1994. 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 42o 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 2008. 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 2005 2006 2006 2007 $$ $ $ (Unaudited) Drilling ...... — 3,209,500 2,621,614 749,862 Seismic ...... — 419,942 332,192 88,897 Other ...... 398,316 698,157 233,115 1,982,649 398,316 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 ...... 2.4 1.1 12.8 Probable Additional ...... 2.9 0.5 20.2 Total Proved + Probable ...... 5.3 1.6 33.0 Total Proved + Probable + Possible ...... 10.1 2.5 61.9

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 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 multi- hundred-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

SUDAN LEGEND

Permits

Albert Graben

Heritage PSA

Oil Wells BLOCK 5 Neptune Country Border

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

Blue LEGEND + Mountains + Lake +Licence Boundary D. R. C Albert Heritage PSA + Waraga-1 + Ngassa-1 BLOCK 4A International Border Open 0 50km Mputa-2 Mputa-1 Pelican + Mputa-4 + O NG Prospect Nzizi-1 Mputa-3 O Nzizi-2 . C + T N D. R BLOCK 4B E M UGANDA Kingfisher-1 Dominion S E + A + B N T i k Block 3A E i

l M + Turaco -3 rt m S E e e A S + Alb B + Graben UGANDA Block 3B Open RWANDA + Rwenzori + Block+ 3C Open MountainsTANZANIABlock 3D Open 14MAR200801100784

42 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 1997. 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 2004. 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 30o 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 30o and 32o 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 2008. A 325 square km 3D seismic survey was carried out over the Kingfisher and neighbouring Pelican structures during the summer of 2007. 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 2007. 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 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 2009. 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 2005 2006 2006 2007 $$ $ $ (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 280 793 1,731 923 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 2006. 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 re- analysing existing seismic data, conducting one 400 km and two 200 km seismic surveys, and drilling four

44 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

22MAR200811412237

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 under- explored area with potential resources. The area has had political stability and has relatively low security risk compared to other areas of Iraq.

45 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 Chemchemal Bai Hassan Suleimaniah Khabbaz Kirkuk

IRAQI KURDISTAN Jambur Kor Mor

35º0’0”N 35º0’0”N Judaida 1 Ajeel 0 50km Hamrin Pulkhana

LEGEND Chia Surkh 2 Gilabat 1 Oil Fields Qamar Gas Fields

Injana 5 Gas Condensate Field

Prospect IRAQ Heritage PSA

44º0’0”E 45º0’0”E 46º0’0”E 14MAR200800540947

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 2007. 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 44-50 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 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 8º 6º 4º 2º 0º 20º 4º 6º 24º 24º LEGEND

Heritage PSA

Exploration Well ALGERIA 22º MALI 22º Well & Gas Shows

International Border Atouila-1

20º 20º 0 100 200km Block 7 050 100m Yarba-1 Kidal In Tamat-1

18º 18º

Tahabanat-1 Timbuktu Block 11 MAURITANIA Tin Bergoui-1 16º Gao 16º Ansongo-1

NIGER Kayes Mopti SENEGAL14º 14º Niamey Sègou Koulikoro BURKINA FASO Bamako 12º 12º Ouagadougou NIGERIA Sikasso GUINEA T BENIN GHANA O 10º G 10º 14º 12º 10º 8º IVORY COAST6º 4º 2º 0º 2º 14MAR2008011009474º

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 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 1980. 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 Lampuko 1 Alexia 1 Gozo 1 Alexia 2 Madonna Taz-Zejt 1ST1 MS-A1 Naxxar 2 Valetta Malta 1 MALTA Aqualta 1 TUNISIA Medina Bank 1 Block 2 Block 7 Sfax Tama 1 Area of seismic coverage

A-001-NC146

B-001-NC087

LEGEND A-001A-NC087 Block boundary

Area of seismic coverage

Exploration Well

Oil & Gas shows

International Border Tarãbulus (Tripoli)

0 50 100km LIBYA 0 25 50m 14MAR200800291616

Pakistan A wholly-owned subsidiary of the Company was awarded a 60 per cent. participating interest in the Sanjawi Block (number 3068-2) 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 Pakistan has current proved hydrocarbon reserves of approximately 289 million bbls and 765 billion m3 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 m3/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 3068-2) and Surrounding Area

64º UZBEKISTAN Dushanbe 72º TAJIKISTAN LEGEND CHINA

Heritage PSA

Oil Fields Gas Fields AFGHANISTAN Gas Condensate Field

International Border Kabul

Gas pipeline Islamabad Peshawar Oil pipeline

Refined product pipeline

32º 32º 0 100 200km PAKISTAN Lahore 050 100m Savi Ragha-1 Dhodak

Khattan Sanjawi Quetta Salsabil

Miriwah -1

Zarghuri South-1 Jandran -1 Khattan

Indus New Delhi

IRAN INDIA

Karachi

24º 24º

64º 72º 14MAR200800541097

7. 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 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 education- oriented, 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 field- based 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 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 1996. 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 1993.

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 1992. 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 1998.

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 in 1993. 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 The Kiame oilfield, offshore Angola operated by Ranger, commenced production in June 1998. Production from the field terminated in April 2002. 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 1989. 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 1996.

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 1996. 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 1999.

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 2004.

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 2000. 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 2002. 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 Mr. Buckingham has never had any association with Aegis and has had no involvement with any military or security operations since the spring of 1998.

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 28-30 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 1992 ...... 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 1993. 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 1998. The Group’s activities were initially funded by share and loan capital provided by Fleming and Premier Oilfields plc. 1993 ...... 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. 1994 - 1996 . . . 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. 1996 ...... 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). 1996 ...... The Group acquired a 10 per cent. interest in Block 8, offshore Oman. This licence contains the West Bukha field. 1997 ...... 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. 1997 ...... 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 Date Event 1998 ...... The Kiame oilfield, offshore Angola, operated by Ranger, commenced production in June 1998. Production from the field terminated in April 2002. The Group held a 5 per cent. net profit interest. 1999 ...... HOC listed the HOC Common Shares on the TSX. 1999 ...... 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. 2001 ...... The Group sold a 50 per cent. working interest in the Uganda Block 3 licence to Energy Africa. 2001 ...... Discovery of the M’Boundi field in the Kouilou exploration permit. 2002 ...... 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. 2004 ...... 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. 2004 ...... The Group is awarded a 50 per cent. working interest in Blocks 1 & 3A in Uganda and is appointed operator. 2005 ...... 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 2007. 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 2006. 2006 ...... 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. 2006 ...... 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. 2006 ...... 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. 2006 ...... 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.

54 Date Event 2007 ...... 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. 2007 ...... 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. 2007 ...... First production from the Zapadno Chumpasskoye field in Russia commenced on 14 May 2007. 2007 ...... The Kingfisher deviated well in Block 3A in Uganda was drilled to a total depth of 3,195 metres. Drilling was completed in March 2007. 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 30o and 32o API) and sweet with a low gas-oil ratio and some associated wax. 2007 ...... 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. 2007 ...... 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 2007. 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. 2007 ...... 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. 2007 ...... 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, 3068-2) in Zone II (Baluchistan) and appointed as operator. 2007 ...... In December 2007, the Group was awarded 100 per cent. of Areas 2 & 7 offshore Malta. 2008 ...... 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.

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 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 non- core 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% 100% 100% 100% 100% 50%

Eagle Heritage Neftynanaya Heritage Energy Heritage Heritage Heritage Heritage Heritage Oil Energy Coatbridge Geologiches Energy (Oman) Ltd. Oil & Gas DRC Mali Mali International Holding Estates Ltd. kaya Middle East (Isle of (U) Ltd. Limited Block 7 Block 11 Malta Ltd. GesmbH (BVI)(6) Kompaniya Ltd. Man)(5) (Uganda)(4) (Nevis) (Nevis) (Nevis) (BVI) (Austria) (Russia) (Nevis)

50% 95%

TISE- Chumpass Heritage NefteDoby Neftegaz cha (Russia) (Russia) 17MAR200823583459

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 (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 2008.

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 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 2005. Mr. Hibberd joined HOC in March 2006.

(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 2005.

(d) Gregory Turnbull Mr. Turnbull is the Regional Managing Partner of the Calgary office of the law firm of McCarthy Tetrault´ 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 1979. 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 Tetrault´ LLP since July 2002. He joined HOC in 1997.

(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 1998.

58 (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 2008. Senior Manager

Non-Executive Name 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 1997.

2. 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 2007 31 December 2006 31 December 2005 Total ...... 89 72 28

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 ...... 84,540,340 33.2%

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 2008. 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 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 Jersey- incorporated 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 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 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 Goldsworth House, Denton Way, Goldsworth Part, Woking, Surrey, GU21 3LG, United Kingdom T +44 (0)1483 746500 F +44 (0)1483 746505 E [email protected] W 17MAR200823583789www.rpsgroup.com

The Directors Heritage Oil Corporation #260 Petex Building, 600 - 6 Ave Sw Calgary, Alberta, Canada, T2P OS5 Project Ref: ECV1377 28 March 2008

Gentlemen,

EVALUATION OF HERITAGE OIL CORPORATION’S PETROLEUM ASSETS In response to your request, and the subsequent Letter of Engagement dated December 3rd 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 30th September 2007, based on data and information available up to 31st December 2007. 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.

RPS Energy Limited: Registered in England No. 1465554, Centurion Court, 85 Milton Park, Abingdon, Oxfordshire OX14 4RY, United Kingdom 17MAR200823583625

63 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) . . 39.5 94.7 228.1 24.6 63.6 167.2 23.9 61.6 163.1 LPG (MMstb) .... 7.4 14.5 27.9 0.745 1.4 2.8 0.180 0.254 0.388 Gas (Bscf) ...... 7.4 47.5 90.0 0.736 4.8 9.0 0.510 1.5 2.3 Table 1: Summary of Heritage Reserves as of 30th 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) ...... 2.1 0.206 0.094 Proved plus Probable Reserves (2P) ...... 2.4 0.243 0.099 Proved plus Probable plus Possible Reserves (3P) ...... 2.6 0.260 0.102 LPG MMstb MMstb MMstb Proved Reserves (1P) ...... 1.5 0.151 0.035 Proved plus Probable Reserves (2P) ...... 2.2 0.225 0.046 Proved plus Probable plus Possible Reserves (3P) ...... 2.5 0.253 0.049 West Bukha Field, Oman Oil MMstb MMstb MMstb Proved Reserves (1P) ...... 9.1 0.906 0.520 Proved plus Probable Reserves (2P) ...... 20.7 2.1 0.764 Proved plus Probable plus Possible Reserves (3P) ...... 39.5 3.9 1.2 Condensate MMstb MMstb MMstb Proved Reserves (1P) ...... 3.9 0.390 0.195 Proved plus Probable Reserves (2P) ...... 8.0 0.794 0.275 Proved plus Probable plus Possible Reserves (3P) ...... 16.1 1.6 0.427 LPG MMstb MMstb MMstb Proved Reserves (1P) ...... 5.9 0.594 0.145 Proved plus Probable Reserves (2P) ...... 12.3 1.2 0.208 Proved plus Probable plus Possible Reserves (3P) ...... 25.4 2.5 0.339 Gas Bscf Bscf Bscf Proved Reserves (1P) ...... 7.4 0.736 0.510 Proved plus Probable Reserves (2P) ...... 47.5 4.8 1.5 Proved plus Probable plus Possible Reserves (3P) ...... 90.0 9.0 2.3 Zapadno Chumpasskoye Field, Russia Oil MMstb MMstb MMstb Proved Reserves (1P) ...... 24.4 23.1 23.1 Proved plus Probable Reserves (2P) ...... 63.6 60.5 60.5 Proved plus Probable plus Possible Reserves (3P) ...... 169.9 161.4 161.4 Table 2: Summary of Reserves for Each Property as of 30th September 2007

64 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 17.2 117.9 493.6 50† 8.6 59.0 246.8 Heritage Total ..... 17.2 117.9 493.6 8.6 59.0 246.8

† 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) . . 55 211 698 267 28 106 349 134 35 Heritage Kingfisher North (Zone P1/M6) 4 32 97 37 2 16 49 19 43 Heritage Kingfisher North (Basal sand) . . 14 56 191 72 7 28 96 36 29 Heritage Pelican Main (Zone P1/M6) . . . 12 59 212 77 6 30 106 39 38 Heritage Pelican Main (Basal sand) ..... 36 127 387 155 18 64 194 78 29 Heritage Pelican North (Zone P1/M6) . . . 0 2 9 3 0 1 5 2 18 Heritage Pelican North (Basal sand) .... 1 5 13 5 1 3 7 3 23 Heritage Pelican Shallow (Zone P1/M6) . 4 15 47 19 2 8 24 10 18 Heritage Pelican Shallow (Basal sand) . . . 6 21 62 25 3 11 31 13 24 Heritage Pelican West (Zone P1/M6) . . . 2 11 41 15 1 6 21 8 23 Heritage Pelican West (Basal sand) ..... 13 44 129 52 7 22 65 26 23 Heritage Pelican (light blue) ...... 10 53 230 78 5 27 115 39 18 Heritage Pelican (light green) ...... 10 53 230 78 5 27 115 39 18 Heritage Lead A (Zone P1/M6) ...... 5 69 560 153 3 35 280 77 13 Heritage Lead A (Basal sand) ...... 22 110 490 169 11 55 245 85 9 Heritage Lead B (Zone P1/M6) ...... 14 83 332 114 7 42 166 57 13 Heritage Lead B (Basal sand) ...... 6 31 133 46 3 16 67 23 9 Heritage Lead C (Zone P1/M6) ...... 68 372 1,338 486 34 186 669 243 12 Heritage Lead C (Basal sand) ...... 28 177 1,012 330 14 89 506 165 9 Heritage Block 1, Uganda Buffalo ...... 111 344 826 420 56 172 413 210 20 Heritage Crocodile ...... 16 31 57 35 8 16 29 18 20 Heritage Giraffe ...... 35 76 161 89 18 38 81 45 20 Heritage Hartebeest ...... 8 24 64 31 4 12 32 16 20 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 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

280 793 1,731 923 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 south- western 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 ...... 464 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$/bbl, MOD 4Q 2007 ...... 88.6 2008 ...... 85.0 2009 ...... 82.0 2010 ...... 80.0 2011 ...... 78.0 2012 ...... 77.0 2013 ...... 77.3 2014 ...... 78.8 2015 ...... 80.4 2016 ...... 82.0 2017 ...... 83.7 2018 ...... 85.3 2019 ...... 87.0 2020 ...... 88.8 2021 ...... 90.6 2022 onwards ...... +2% p.a. Table 7: RPS Price Base Case Forecasts (US$/bbl Money of the Day)

66 The post tax Net Present Value (NPV) at various discount rates4 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) ...... 2029 2.2 1.7 1.4 1.2 1.0 Proved plus Probable Reserves (2P) ...... 2029 2.8 2.1 1.7 1.4 1.2 Proved plus Probable plus Possible Reserves (3P) . . 2029 3.0 2.3 1.7 1.4 1.2 West Bukha Field, Oman Proved Reserves (1P) ...... 2037 15.5 13.2 11.4 9.9 8.7 Proved plus Probable Reserves (2P) ...... 2037 39.9 35.1 31.3 28.3 25.7 Proved plus Probable plus Possible Reserves (3P) . . 2037 79.7 68.6 60.2 53.6 48.3 Zapadno Chumpasskoye Field, Russia Proved Reserves (1P) ...... 2025 69.1 40.2 17.5 0.2 32.9 Proved plus Probable Reserves (2P) ...... 2029 413.6 308.0 226.6 163.5 46.7 Proved plus Probable plus Possible Reserves (3P) . . 2031 1356.2 1013.7 762.2 574.5 238.2

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 30th 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 2nd October 2007. 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 NPV10 per recoverable barrel is given in Table 9:

Value (NPV10) per recoverable barrel Miran ...... US$2.6

Table 9: Success Case NPV10 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 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

27MAR200808225692

EurIng Roy T. Kelly, CEng, FEI Technical Director

68 RPS Energy Heritage Oil – Competent Persons Report

TABLE OF CONTENTS

Page 1. DESCRIPTION OF ASSETS ...... 74 1.1. Overview ...... 74 1.2. Liabilities ...... 77 2. METHODS USED IN THIS REPORT ...... 77 2.1. General ...... 77 2.2. Reserves and Resource Classification ...... 77 2.3. Risk Assessment ...... 77 2.3.1. Contingent Resources ...... 77 2.3.2. Prospective Resources (Exploration Prospects) ...... 78 2.4. Uncertainty Estimation ...... 78 3. OMAN BLOCK 8 ...... 78 3.1. Overview ...... 78 3.2. Bukha Field ...... 79 3.2.1. Database ...... 79 3.2.2. Geology and Geophysics ...... 79 3.2.3. In Place Volumes ...... 80 3.2.4. Petroleum Engineering ...... 80 3.2.5. Interaction with the West Bukha Field ...... 82 3.3. West Bukha Field ...... 83 3.3.1. Database ...... 83 3.3.2. Geology & Geophysics ...... 83 3.3.3. In Place Volumes ...... 85 3.3.4. Petroleum Engineering ...... 87 4. ZAPADNO CHUMPASSKOYE ...... 93 4.1. Data Available ...... 94 4.2. Geology ...... 94 4.2.1. Regional Setting ...... 94 4.2.2. Zapadno Chumpasskoye Field ...... 94 4.2.3. Petrophysics ...... 95 4.3. In Place Volumes ...... 97 4.4. Petroleum Engineering ...... 98 4.4.1. Reservoir Fluid Properties ...... 98 4.4.2. Well Performance & Deliverability ...... 98 4.4.3. Development Plan (Subsurface) ...... 99 4.4.4. Recovery Mechanisms ...... 100 4.4.5. Production Profiles ...... 101 4.5. Facilities and Costs ...... 105 5. UGANDA—BLOCKS 1 & 3A ...... 105 5.1. Overview ...... 105 5.2. Data Available ...... 105 5.3. Geological Setting ...... 106 5.4. Geology & Geophysics ...... 107 5.4.1. Kingfisher 1 ...... 107 5.4.2. Mapping ...... 109 5.4.3. Prospectivity ...... 109 5.5. Volumetrics ...... 110 5.6. Other Prospectivity ...... 113 5.7. Petroleum Engineering ...... 114 5.7.1. Production Profiles for Kingfisher and Other Block 3A Prospects ...... 114 5.7.2. Production Profiles for Block 1 Prospects ...... 115

69 RPS Energy Heritage Oil – Competent Persons Report

Page 6. KURDISTAN—MIRAN BLOCK ...... 116 6.1. Data Available ...... 116 6.2. Geology ...... 116 6.3. In place volumes ...... 116 6.4. Reservoir Engineering ...... 117 6.5. Facilities and Costs ...... 118 7. ECONOMICS ...... 118 7.1. Valuation Assumptions ...... 118 7.1.1. General ...... 118 7.1.2. Oil Prices ...... 119 7.2. Valuation Methodology ...... 120 7.2.1. Reserves ...... 120 7.2.2. Contingent and Prospective Resources ...... 120 7.2.3. Other (Miran) ...... 120 7.3. Oman—Block 8 ...... 120 7.3.1. Fiscal Regime and Contract Terms ...... 120 7.3.2. Price Assumptions ...... 120 7.3.3. Unrecovered Costs ...... 121 7.3.4. Valuation Summary—Bukha ...... 121 7.3.5. Valuation Summary—West Bukha ...... 122 7.3.6. Sensitivity to Oil Price ...... 122 7.4. Russia—Zapadno Chumpasskoye ...... 123 7.4.1. Fiscal Regime and Contract Terms ...... 123 7.4.2. Price Assumptions ...... 124 7.4.3. Transportation Costs ...... 124 7.4.4. Tax Losses ...... 124 7.4.5. Valuation Summary ...... 124 7.4.6. Sensitivity to Oil Price ...... 125 7.5. Kurdistan—Miran Block ...... 125 7.5.1. Fiscal Regime and Contract Terms ...... 125 7.5.2. Price Assumptions ...... 125 7.5.3. Valuation summary ...... 126 APPENDIX A: GLOSSARY OF TECHNICAL TERMS ...... 127 APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS ...... 129

70 RPS Energy Heritage Oil – Competent Persons Report

List of Figures

Page Figure 1: Omani Licence Location Map ...... 75 Figure 2: Russian Licence Location Map ...... 75 Figure 3: Kurdistan Licence Location Map ...... 76 Figure 4: Ugandan & DRC Licences Location Map ...... 76 Figure 5: Bukha Field—Top Reservoir Depth Map ...... 79 Figure 6: Bukha Wet Gas History and Forecast ...... 81 Figure 7: Condensate Yield vs. Cumulative Wet Gas Production ...... 82 Figure 8: LPG yield vs. Cumulative Wet Gas Production ...... 82 Figure 9: Top Mishrif Depth Map ...... 84 Figure 10: West Bukha 3D inline 1122 ...... 85 Figure 11: 1P Production Profile for West Bukha ...... 92 Figure 12: 2P Production Profile for West Bukha ...... 92 Figure 13: 3P Production Profile for West Bukha ...... 93

Figure 14: Lower J1 Sand—RPS Net Pay Map (p50 Case) ...... 95 Figure 15: CPI for Well P3 over Reservoir Interval for p50 Saturation Case ...... 97 Figure 16: Well 226 Production History ...... 98 Figure 17: Well P3 Production History ...... 99 Figure 18: Illustration of Inverted Five-spot Patterns at Zapadno Chumpasskoye ...... 100 Figure 19: Oil Rate & Cumulative from Full Field Simulation ...... 101 Figure 20: Water Injection Rate & Cumulative from Full Field Simulation ...... 101 Figure 21: Average Reservoir Pressure from Full Field Simulation ...... 102 Figure 22: 1P Production Profile for Zapadno Chumpasskoye ...... 103 Figure 23: 2P Production Profile for Zapadno Chumpasskoye ...... 103 Figure 24: 3P Production Profile for Zapadno Chumpasskoye ...... 104 Figure 25: Seismic Section through Kingfisher 1 Well ...... 107 Figure 26: Reservoir Section in Kingfisher 1A ...... 108 Figure 27: RPS Cycle P1/M6 Depth Map, Block 3A ...... 108 Figure 28: RPS Top Reservoir Depth Map, Block 1 ...... 110 Figure 29: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS (MMstb) ...... 113 Figure 30: Generic, Scalable Profile for Block 3A Prospects ...... 115 Figure 31: Generic, Scalable Profile for Block 1 Prospects & Leads ...... 115 Figure 32: Assumed Well Profiles for Miran Wells ...... 118 Figure 32: RPS Base Forecast Price ...... 119 Figure 33: Plot of Brent vs. URALS (Mediterranean)—1997 to 2007 ...... 124

Figure 34: Heritage Net NPV10 vs. Notional Field Size Showing Price Sensitivity ...... 126

71 RPS Energy Heritage Oil – Competent Persons Report

List of Tables Page Table 1: Summary of Heritage Reserves as of 30th September 2007 ...... 64 Table 2: Summary of Reserves for Each Property as of 30th September 2007 ...... 64 Table 3: Summary of Contingent Resources Reviewed by RPS ...... 65 Table 4: Summary of Prospective Resources Reviewed by RPS (MMstb) ...... 65 Table 5: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS...... 66 Table 6: Heritage Unrisked Conceptual Leads (Not Reviewed by RPS) ...... 66 Table 7: RPS Price Base Case Forecasts (US$/bbl Money of the Day) ...... 66 Table 8: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves as of 30th September 2007 ...... 67

Table 9: Success Case NPV10 US$/per Recoverable Barrel (p50 case) ...... 67 Table 10: Summary of Heritage’s Properties ...... 74 Table 11: Range of GIIP for the Bukha Field (Full Field Interest)—from Novus Volumetrics Study February 2003 ...... 80 Table 12: West Bukha Volumetric Input Parameters ...... 87 Table 13: West Bukha In place Volumes 100 per cent. Basis ...... 87 Table 14: Summary of West Bukha & Henjam Well Tests ...... 88 Table 15: Initial Composition of West Bukha Wellstream ...... 89 Table 16: Estimated Product Yields from West Bukha Wellstream ...... 91

Table 17: Lower J1 Sand Input Parameters ...... 97

Table 18: Zapadno Chumpasskoye, Lower J1 Sand STOIIP Estimates (MMstb) ...... 97 Table 19: The p90 and p50 Drilling Schedule for Zapadno Chumpasskoye ...... 102 Table 20: Summary of Results for Zapadno Chumpasskoye ...... 104 Table 21: Uganda Volumetric Input Parameters ...... 111 Table 22: Kingfisher Discovery—STOIIP and Contingent Resource Estimate (100 per cent. Basis) ...... 111 Table 23: Block 1 & 3A—STOIIP and Prospective Resource Estimates (On-block, 100 per cent. Basis) ...... 112 Table 24: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS...... 113 Table 25: Heritage Conceptual Leads Mean Un-Risked STOIP (100 per cent. Basis) Not Reviewed by RPS) ...... 114 Table 26: Summary of Kingfisher-1A Well Tests ...... 114 Table 27: Summary of Kingfisher-1 Fluid Properties ...... 114 Table 28: Assumptions Used For Profiles ...... 114 Table 29: Miran Field—Range of Notional STOIIP ...... 116 Table 30: Assumptions Used in Miran Profiles ...... 117 Table 31: RPS Forecast Price Cases ...... 119 Table 32: Table of Base Case Forecast Prices ...... 120 Table 33: Bukha Post-Tax Valuation (Net Heritage Share) ...... 121 Table 34: Bukha Reserves Summary ...... 121 Table 35: West Bukha Post-Tax Valuation (Net Heritage Share) ...... 122 Table 36: West Bukha Reserves Summary ...... 122

Table 37: Sensitivity of Bukha NPV10 to Oil Price ...... 122

72 RPS Energy Heritage Oil – Competent Persons Report

Page

Table 38: Sensitivity of West Bukha NPV10 to Oil Price ...... 123 Table 39: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share) ...... 124 Table 40: Zapadno Chumpasskoye Reserves Summary ...... 125

Table 41: Sensitivity of Zapadno Chumpasskoye NPV10 to Oil Price ...... 125

Table 42: Net NPV10 and Average for NPV10 /stb for a Range of Notional Field Sizes ...... 126

73 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 8 ...... 423.00 April 1985 10% Rak Petroleum, LG RUSSIA Zapadno 195.65 September 1999 95% Chumpasskoye UGANDA Block 1† ...... 3,659.00 July 2004 50% Tullow Oil Block 3A† ..... 2,024.50 September 2004 50% Tullow Oil KURDISTAN Miran Block†† . . . 1,015 .00 October 2007 100% D.R. CONGO Block I ...... 3,825.00 Signed July 2006 39.5% Tullow Oil, (awaiting Presidential Decree) Cohydro Block II ...... 2,634.00 Signed July 2006 39.5% Tullow Oil, (awaiting Presidential Decree) Cohydro MALI Block 7 ...... 39,804.00 July 2006 75% Centric Energy Block 11 ...... 32,810.00 June 2005 75% Centric Energy MALTA Area 2 ...... 9,190.00 December 2007 100% Area 7 ...... 8,778.00 December 2007 100% PAKISTAN Sanjawi Permit . . 2,412.00 November 2007 60% 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 RPS Energy Heritage Oil – Competent Persons Report

Locations of the properties are shown in Figure 1 to Figure 4.

21FEB200823161520 Figure 1: Omani Licence Location Map

21FEB200823162333 Figure 2: Russian Licence Location Map

75 RPS Energy Heritage Oil – Competent Persons Report

21FEB200823153649 Figure 3: Kurdistan Licence Location Map

BLOCK 5 Neptune

BLOCK 1 Heritage DEMOCRATIC REPUBLIC

BLOCK I OF CONGO Tullow

BLOCK 2 Tullow Waraga-1 Ngassa-1 Mputa-2 BLOCK II Mputa-1 Tullow Mputa-4 Kingfisher-1 Mputa-3 0 100km Nzizi-1 Nzizi-2

BLOCK III BLOCK 3A Heritage LEGEND Open BLOCK 3B Open

Permits BLOCK 3C Open BLOCK 3D Open Heritage PSA BLOCK IV Albert Graben Open UGANDA Country Border BLOCK 4A Open

Oil Well

BLOCK V Dominion BLOCK 4B Dominion 25MAR200814223227 Figure 4: Ugandan & DRC Licences Location Map

76 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).

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.

2.3. 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.

2.3.1. 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 RPS Energy Heritage Oil – Competent Persons Report

2.3.2. 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.

2.4. 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, Sw, 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 8 3.1. 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 Semail 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 Semail 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 Semail 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., 1987. Dealing with Risk and Uncertainty in Exploration: How Can We Improve? AAPG Bulletin, 71 (1), pp. 1-16. (3) Rose, R.P. and Edwards, B., 2001. Could this prospect turn out to be a mediocre little one-well field? Abstract, AAPG Bulletin, 84(13)

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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 1979. 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 1994.

3.2.1. Database The Bukha Field is covered by 2D seismic data that was acquired over a considerable span of time from 1974 to 1986. These data have been the subject of a reprocessing exercise in 2001. 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.

3.2.2. 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.

21FEB200823150007 Figure 5: Bukha Field—Top Reservoir Depth Map

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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).

3.2.3. 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 2003. 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 ...... 110 182 284 Thamama ...... 143 231 330 Total ...... 297 417 565

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 2003

3.2.4. Petroleum Engineering 3.2.4.1. Reservoir Temperature, Pressure and Gas Properties Reservoir properties at the time of discovery were a pressure of 7,147 psig and a temperature of 295F. 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 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 2007.

3.2.4.2. 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.

3.2.4.3. 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 2007

50 1P Forecast 2P Forecast 3P Forecast Dec-07 40

20 Wet Gas Rate (MMscf/d)

0 1998 2000 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 21FEB200823144965 Figure 6: Bukha Wet Gas History and Forecast

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).

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70 140 Wet Gas Rate - History Wet gas rate 2007 60 October 2007 cut off 120 Condensate Yield Condensate yield 2007 50 Condensate match 100

40 80

30 60 Wet Gas Rate (MMscf/d) Wet Gas Rate

20 40 Condensate yield (bbls/MMscf)

History Forecast

10 20

0 0 0 50 100 150 200 250 300 Cumulative Gas (Bscf) 21FEB200823150473 Figure 7: Condensate Yield vs. Cumulative Wet Gas Production

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 C3 and C4 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 C3 and C4 based on sales statements from 2007, that being 43 per cent. for propane and 57 per cent. for butane.

60 35

30 50

25 40

20 yield (bbls/MMscf)LPG Wet Gas Rate - History 10 Wet gas rate (MMscf/d) Wet gas rate 2007 October cut off History Forecast 10 LPG Yield 5 1P Forecast 2P & 3P Forecast

0 0 0 50 100 150 200 250 300 Cumulative wet gas (Bscf) 21FEB200823153850 Figure 8: LPG yield vs. Cumulative Wet Gas Production

3.2.5. 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 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 3rd Quarter 2008. 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.

3.3. 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 1977. 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.

3.3.1. Database The West Bukha field is covered by 2D seismic acquired from 1974-1986, 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.

3.3.2. 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.

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21FEB200823154113 Figure 9: Top Mishrif Depth Map

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.

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26FEB200822314633 Figure 10: West Bukha 3D inline 1122

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-1.

3.3.3. In Place Volumes RPS calculated in place volumes for the Mishrif/Mauddud and for the Thamama.

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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 Sw difficult and Sw varies markedly between the West Bukha-1 and -2 wells. A wide range of Sw has been used in the probabilistic calculation. A normal distribution of Sw 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.

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A summary of input rock and fluid properties is given in Table 12.

Low Mid High Mishrif/Mauddud GRV...... MM m3 1,671 3,844 4,023 N:G...... % 1 1 1 Porosity-Mish-Maudd ...... % 1.3 1.7 2.1 Porosity- Mish 2&3 ...... % 1.7 2.85 4.0 Sw...... % 50 33 18.5 1/FVF ...... stb/rb 0.392 0.370 0.351 Thamama GRV...... MM m3 559 1,091 1,622 N:G...... 1 1 1 Porosity ...... % 1.6 2.3 3.0 Sw...... % 50 40 30 1/FVF ...... stb/rb 0.488 0.455 0.426 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 ...... 168.0 242.0 331.0 53.6 82.9 119.0 Thamama ...... 54.5 88.5 136 24.8 41.2 62.7 Total ...... 252.0 335.0 434.0 91.2 126.0 267.0

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

3.3.4. Petroleum Engineering 3.3.4.1. 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 (‘‘C1’’) content is below 60mol per cent.; The test separator GOR is <3,000 scf/stb; The Heptanes plus (‘‘C7+’’) 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. H2S has been measured in the reservoir samples, and approximately 14 mol per cent. CO2 and N2.

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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).

3.3.4.2. 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-1 ...... 1 1975 3,970-3,980 Mauddud 2,910 13.6 26/64 3,640 (10m interval) Hengam-2 ...... 1 April, 2006 4,072-4,110 Thamama 196 0.61 20/64 506 (38m interval) Hengam-2 ...... 3 July, 2006 3,732-3,907 Mishrif 5,090 14.1 64/64 1,477 (35m interval) West Bukha-1A ...... 1 June, 1987 4,086- Thamama 1,205 3.9 32/64 1,467 2 June, 1987 3,846- Mauddud 543 2.3 48/64 147 3 June, 1987 3,729- Mishrif 459 2.7 128/64 123 West Bukha-2A ...... 1 Nov., 2006 3,521-3,541 Thamama 4,525 7.5 50/64 1,652 (20m interval) 2 Nov., 2006 4,005-4,127.5 Mishrif 8,480 24.9 72/64 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, ke ...... 0.673 mD Total skin, S ...... 6.95 Omega, ȣ ...... 0.0389 (a measure of fracture storage) Lambda, ȕ ...... 5.32 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 %

H2 Hydrogen ...... 0.10 0.00 H2S Hydrogen Sulphide ...... 1.42 0.95 CO2 Carbon Dioxide ...... 8.48 7.42 N2 Nitrogen ...... 5.47 3.01 C1 Methane ...... 53.70 16.95 C2 Ethane ...... 5.01 2.96 C3 Propane ...... 3.32 2.87 iC4 i-Butane ...... 1.04 1.19 nC4 n-Butane ...... 1.93 2.20 C5 Neo-Pentane ...... 0.02 0.03 iC5 I-Pentane ...... 1.05 1.48 nC5 n-Pentane ...... 1.09 1.54 C6 Hexanes ...... 1.56 2.64 M-C-Pentane ...... 0.33 0.54 Benzene ...... 0.28 0.43 Cyclohexane ...... 0.48 0.80

C7 Heptanes ...... 1.10 2.17

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Component Mole % Weight % M-C-Hexane ...... 0.52 1.01 Toluene ...... 0.64 1.15

C8 Octanes ...... 1.18 2.64 E-Benzene ...... 0.14 0.30 M/P-Xylene ...... 0.48 1.00 O-Xylene ...... 0.16 0.34

C9 Nonanes ...... 0.98 2.48 1,2,4-TMB ...... 0.19 0.45

C10 Decanes ...... 1.17 3.26 C11 Undecanes ...... 1.03 2.98 C12 Dodecanes ...... 0.86 2.73 C13 Tridecanes ...... 0.78 2.68 C14 Tetradecanes ...... 0.66 2.47 C15 Pentadecanes ...... 0.62 2.52 C16 Hexadecanes ...... 0.49 2.12 C17 Heptdecanes ...... 0.40 1.87 C18 Octadecanes ...... 0.36 1.78 C19 Nonadecanes ...... 0.34 1.76 C20 Eicosanes ...... 0.29 1.59 C21 Heneicosanes ...... 0.24 1.40 C22 Docosanes ...... 0.22 1.33 C23 Tricosanes ...... 0.19 1.19 C24 Tetracosanes ...... 0.17 1.11 C25 Pentacosanes ...... 0.15 1.01 C26 Hexacosanes ...... 0.14 0.96 C27 Heptacosanes ...... 0.12 0.92 C28 Octacosanes ...... 0.11 0.83 C29 Nonacosanes ...... 0.10 0.78 C30 Triacontanes ...... 0.10 0.79 C31 Hentriacontanes ...... 0.08 0.67 C32 Dotriacontanes ...... 0.08 0.71 C33 Tritriacontanes ...... 0.05 0.43 C34 Tetratriacontanes ...... 0.06 0.56 C35 Penatriacontanes ...... 0.05 0.51 C36+ Hexatriacontanes Plus ...... 0.37 4.49 Totals ...... 100.00 100.00 Note: 0.00 means < 0.005 Table 15: Initial Composition of West Bukha Wellstream

3.3.4.3. 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.

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3.3.4.4. 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.

3.3.4.5. 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.

3.3.4.6. 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.

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Estimation of the Product Streams

In addition to the above estimation of the ‘‘black’’ oil production, reserves estimates of C3, C4, 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...... 1.461 ft3 17.047 ft3 C3...... 0.0574 stb 0.5529 stb C4...... 0.0549 stb 0.4789 stb LPG total ...... 0.1122 stb 1.0319 stb Condensate ...... 0.0867 stb 0.6530 stb Mishrif Dry gas...... 1.922 ft3 13.147 ft3 C3...... 0.0650 stb 0.3959 stb C4...... 0.0559 stb 0.3282 stb LPG total ...... 0.1209 stb 0.7241 stb Condensate ...... 0.0841 stb 0.4319 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.

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The production profiles for the 1P, 2P and 3P cases are shown in Figure 11 to Figure 13.

8,000 16.0

7,000 14.0

6,000 12.0

5,000 10.0

4,000 8.0 (stb/d)

3,000 6.0 Sales Gas Rate (MMscf/d)

2,000 4.0 Oil, Propane, Butane & Condensate Annual Average Rate 1,000 2.0

0 0.0

8 24 7 28 36 7 021 26 2009 2010 2011 2012 2013 2014 2015 2016 2017 201 2019 2020 2 2022 2023 20 2025 20 202 20 2029 2030 2031 2032 2033 2034 2035 20 203 Black Oil Propane Butane Condensate Sales Gas 26FEB200822320154 Figure 11: 1P Production Profile for West Bukha

25,000 50

20,000 40

35 ) 15,000 30 MMscf/d

25 (

10,000 20 Gas Rate Liquid Rates (stb/d)

5,000 10

0 0 8 9 0 1 2 3 4 6 7 1 9 200 200 201 201 201 201 201 2015 201 201 2018 2019 2020 202 2022 2023 2024 2025 2026 2027 2028 202 2030 2031 2032 2033 2034 2035 2036

NB "2008" is only the period 1/11/08 to 31/12/08

Black Oil (stb/d) Propane (stb/d) Butane (stb/d) Condensate (stb/d) Sales Gas (MMscf/d)27FEB200804263036 Figure 12: 2P Production Profile for West Bukha

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30,000 40

35 25,000

20,000 25

15,000 20

15 10,000 Gas Rate (MMscf/d) Liquid Rates (stb/d) 10

5,000 5

0 0

8 9 0 11 2 4 16 7 8 20 23 24 5 6 27 28 29 0 1 32 33 4 5 6 200 200 201 20 201 2013 201 2015 20 201 201 2019 20 2021 2022 20 20 202 202 20 20 20 203 203 20 20 203 203 203 NB "2008" is only the period 1/09/08 to 31/12/08

Black Oil (stb/d) Propane. C3H8 (stb/d) Butane, C4H10 (stb/d) Condensate (stb/d) Sales Gas (MMscf/d)27FEB200804263181 Figure 13: 3P Production Profile for West Bukha

Economically recoverable reserves are discussed in the economics section, Section 7, below.

3.3.4.7. 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.

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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.

4.2. Geology 4.2.1. 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.

4.2.2. 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 J1 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 J1 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 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.

21FEB200823155320

Figure 14: Lower J1 Sand—RPS Net Pay Map (p50 Case)

4.2.3. Petrophysics

RPS undertook an independent petrophysical review of wells P2ST and P3. The Sw 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 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 Rw 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 0.277 Ohmm at 20 C with standard deviation of the mean of 0.012 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 Rw of 0.143 Ohmm at 20 C. Because of the ambiguity in the results from the brine analyses, the 0.277 Ohmm Rw at 20 C was used to calculate saturations at the p90 level, and the 0.143 Ohmm Rw 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 Rw of 0.143 Ohm at 20 C. An Rw of 0.277 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, 327-330. (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 12th Annual Logging Symposium, May 2-5 1971.

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21FEB200823151631 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 Sw a broad range of Sw was used in the volumetric calculations. Input parameters are shown in Table 17.

Low Mid High Net Pay Rock Volume (MM m3)...... 131 455 854 Porosity (%) ...... 15 17 19 Oil Saturation (%) ...... 45 060 65

Boi (rb/stb) ...... 1.2 1.25 1.30

Table 17: Lower J1 Sand Input Parameters

STOIIP has been estimated probabilistically and is summarised Table 18 below.

STOIIP (MMstb) p90 p50 p10 90.3 233 419

Table 18: Zapadno Chumpasskoye, Lower J1 Sand, STOIIP Estimates (MMstb)

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4.4. Petroleum Engineering 4.4.1. Reservoir Fluid Properties

The Lower J1 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 (Rsi) is 410 scf/stb, and the initial formation volume factor (Boi) is 1.25 rb/stb.

4.4.2. 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 476.5 stb/d and 288.9 stb/d, respectively.

27FEB200804263806 Figure 16: Well 226 Production History

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27FEB200804271079 Figure 17: Well P3 Production History

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).

4.4.3. 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).

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27FEB200804274190 Figure 18: 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.

4.4.4. 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.

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4.4.5. 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.

22FEB200803400027 Figure 19: Oil Rate & Cumulative from Full Field Simulation

22FEB200803401971 Figure 20: Water Injection Rate & Cumulative from Full Field Simulation

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22FEB200803404094 Figure 21: Average Reservoir Pressure from Full Field Simulation

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 m3/d (7,548 stb/d) following water injection which builds to a peak rate of 2,800 m3/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.

2007 2008 2009 2010 2011 2012 2013 2014 2015 p90 New Producers ...... 2 4 8 16 16 2 Cumulative Producers ...... 3 7 15 31 47 49 New Injectors ...... 4 8 8 12 Cumulative Injectors ...... 0 0 4 12 20 32 Total in Year ...... 2 4 12 24 24 14 p50 New Producers ...... 2 4 8 16 14 14 13 10 2 Cumulative Producers ...... 3 7 15 31 45 59 72 82 84 New Injectors ...... 4888981 Cumulative Injectors ...... 0 0 0 8 16 24 33 41 46 Total in Year ...... 0 4 12 24 22 22 22 18 3 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 0.048 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.

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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

4,000

Gross Oil Rate (stb/d) 3,000

2,000

1,000

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 202527FEB200804332882 2026 2027 2028 Figure 22: 1P Production Profile for Zapadno Chumpasskoye

18,000

16,000

14,000

12,000

10,000

8,000 Gross Oil Rate (stb/d)

6,000

4,000

2,000

0 3 9 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 202 2024 2025 2026 2027 2028 20227FEB2008043330812030 2031 2032 Figure 23: 2P Production Profile for Zapadno Chumpasskoye

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50,000

45,000

40,000

35,000

30,000

25,000

20,000 Gross Oil Rate (stb/d)

15,000

10,000

5,000

0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 202927FEB200804333226 2030 2031 2032 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) ...... 90.3 233.0 419.0 URR(11) (MMstb) ...... 24.9 64.4 172.8 URR/well (MMstb) ...... 0.509 0.767 0.971 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.

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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.

4.5. 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 2012. The p50 Case is expected to produce over 60 MMstb peaking at about 16,000 bopd in 2014. 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 2011. 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.

5.2. Data Available The seismic database in Block 3A comprises 16 widely spaced 2D seismic lines of varying vintages 2003-2005. 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 2008. 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 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. Fluvio- deltaic 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 fluvio- lacustrine 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 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.

5.4. Geology & Geophysics 5.4.1. 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.

22FEB200803421223 Figure 25: Seismic Section through Kingfisher 1 Well

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 RPS Energy Heritage Oil – Competent Persons Report

22FEB200803423317 Source: Heritage Figure 26: Reservoir Section in Kingfisher 1A

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.

22FEB200803425435 Figure 27: RPS Cycle P1/M6 Depth Map, Block 3A

108 RPS Energy Heritage Oil – Competent Persons Report

5.4.2. 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.

5.4.3. 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 RPS Energy Heritage Oil – Competent Persons Report

22FEB200803432250 Figure 28: RPS Top Reservoir Depth Map, Block 1

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.

5.5. 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 Sw 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 RPS Energy Heritage Oil – Competent Persons Report

Water saturations calculated from petrophysics by both Heritage and RPS have anomalously high values, between 50-80 per cent., which both RPS and Heritage consider to be unrepresentative due to the intercalated shale section suppressing the resistivity curves. An Sw range of 20-50 per cent. has been used for Kingfisher and a larger range in the prospects outside of the immediate Kingfisher area. In Block 1, a large range of sand thicknesses has been used as the area is untested. Block 1 lies at the northern part of Lake Albert which at present day has a sand rich fluvial system related to the Nile River. Sands are expected to be thicker in this block than in Block 3a and field work undertaken by Heritage has been used to support thickness estimates. Relatively higher porosity values have been used to account for the shallow burial depth. A summary of input values for the volumetrics is given in Table 21.

N:G (%) Porosity (%) Sw Boi (rb/stb) p90 p50 p10 p90 p50 p10 p90 p50 p10 p90 p50 p10 Discovery Kingfisher Main P2a ...... 69 80 90 24 25 26 50 40 20 1.11 1.13 1.15 Kingfisher Main P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17 Prospects Kingfisher Main Basal sand ...... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18 Kingfisher North Cycle P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17 Kingfisher North Basal sand ...... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18 Pelican Light blue ...... 40 60 80 20 25 30 60 40 20 1.00 1.08 1.16 Pelican Light green ...... 40 60 80 20 25 30 60 40 20 1.00 1.08 1.15 Pelican Main Cycle P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17 Pelican Main Basal sand ...... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18 Pelican North Cycle P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17 Pelican North Basal sand ...... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18 Pelican Shallow Cycle P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17 Pelican Shallow Basal sand ...... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18 Pelican West Cycle P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17 Pelican West Basal sand ...... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18 Lead A Cycle P1/M6 ...... 40 60 80 15 20 25 50 40 20 1.15 1.16 1.17 Lead A Basal sand ...... 50 70 90 12 17 22 50 40 20 1.16 1.17 1.18 Lead B Cycle P1/M6 ...... 40 60 80 15 20 25 50 40 20 1.15 1.16 1.17 Lead B Basal sand ...... 50 70 90 12 17 22 50 40 20 1.16 1.17 1.18 Lead C Cycle P1/M6 ...... 40 60 80 15 20 25 50 40 20 1.15 1.16 1.17 Lead C Basal sand ...... 50 70 90 12 17 22 50 40 20 1.16 1.17 1.18 Buffalo ...... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10 Crocodile ...... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10 Giraffe ...... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10 Hartebeest ...... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10 Table 21: Uganda Volumetric Input Parameters

The estimated in place and recoverable Contingent Resources in Kingfisher structure are given in Table 22. Recovery factors of 20, 30 and 40 per cent. have been applied deterministically to the p90, p50 and p10 in-place volumes, respectively. Contingent Resources In Place Volume (MMstb) (MMstb) Low Best High (p90) (p50) (p10) Mean 1C 2C 3C P2a...... 9.4 13.4 18.5 13.7 1.9 4.0 7.4 P1/M6 Cycle ...... 74.5 382.0 1223.0 541.0 14.9 114.6 489.2 Total ...... 86.2 393.0 1234.0 554.7 17.2 117.9 493.6

N.B. The totals are the p90, p50 and p10 of the stochastically consolidated distributions Table 22: Kingfisher Discovery—STOIIP and Contingent Resource Estimate (100 per cent. Basis)

111 RPS Energy Heritage Oil – Competent Persons Report

The wide range between the p90 and p10 STOIIP reflects the inherent uncertainty in the continuity of the tested sands and in particular the shallowest sand in Kingfisher 1A, which RPS interprets to be a channel sand. The estimated in place and recoverable Prospective Resources in Uganda Blocks 1 and 3A are given in Table 23. Recovery factors of 20, 30 and 40 per cent. have been applied deterministically to the p90, 050 and p10 in-place volumes, respectively. STOIIP Prospective Resources (MMstb) (MMstb) Low Best High Low Best High GPoS (p90) (p50) (p10) Mean (p90) (p50) (p10) Mean (%) Block 3A Kingfisher main (Basal Sand) ...... 275 704 1,746 890 55 211 698 267 35 Kingfisher north (P1/M6) ...... 22 105 243 123 4 32 97 37 43 Kingfisher north (Basal sand) ...... 69 188 478 240 14 56 191 72 29 Pelican main (P1/M6) ...... 59 195 529 257 12 59 212 77 38 Pelican main (Basal sand) ...... 178 422 968 517 36 127 387 155 29 Pelican north (P1/M6) ...... 1 7 22 9 0 2 9 3 18 Pelican north (Basal sand) ...... 7 15 33 18 1 5 13 5 23 Pelican shallow (P1/M6) ...... 21 51 118 63 4 15 47 19 18 Pelican shallow (Basal sand) ...... 30 69 154 82 6 21 62 25 24 Pelican west (P1/M6) ...... 11 38 102 49 2 11 41 15 23 Pelican west (Basal sand) ...... 63 146 323 174 13 44 129 52 23 Pelican (light blue) ...... 48 176 574 261 10 53 230 78 18 Pelican (light green) ...... 48 176 574 261 10 53 230 78 18 Lead A (P1/M6) ...... 23 231 1,399 511 5 69 560 153 13 Lead A (Basal sand) ...... 111 368 1,224 562 22 110 490 169 9 Lead B (P1/M6) ...... 68 277 829 381 14 83 332 114 13 Lead B (Basal sand) ...... 32 102 333 154 6 31 133 46 9 Lead C (P1/M6) ...... 339 1,241 3,345 1,620 68 372 1,338 486 12 Lead C (Basal sand) ...... 139 589 2,531 1,101 28 177 1,012 330 9 Block 1 Buffalo ...... 444 1,375 3,305 1,678 111 344 826 420 20 Crocodile ...... 65 124 228 138 16 31 57 35 20 Giraffe ...... 139 305 643 356 35 76 161 89 20 Hartebeest ...... 32 97 255 124 8 24 64 31 20 Total Mean ...... 9,569 2,756

† 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 the mean of the distribution produced by the process of statistical addition. Table 23: Block 1 & 3A—STOIIP and Prospective Resource Estimates (On-block, 100 per cent. Basis)

112 RPS Energy Heritage Oil – Competent Persons Report

Given the range of resources in the Albert Basin, the gross risked recoverable Contingent and Prospective resources have been consolidated stochastically and the p90, p50, p10 and mean is quoted in Table 24 and presented graphically in Figure 29.

Gross Risked Recoverable Resources (MMstb) p90 p50 p10 Mean

280 793 1,731 923 Table 24: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS

Total Risked Recoverable Resources

120%

100%

80%

60%

40%

Cumulative exceedance probability exceedance Cumulative 20%

0% 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 Gross risked recoverable resources 22FEB200803434111 Figure 29: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS (MMstb)

5.6. Other Prospectivity In an effort to obtain a full valuation of the potential prospectivity of all of their acreage in Uganda and to plan future exploration strategies, Heritage made estimates of the potential that the under-explored areas may offer. This was beyond the scope of the RPS evaluation. Heritage recognises conceptual leads in areas beyond seismic control. These conceptual leads are based on Heritage’s extensive regional and structural knowledge of the area together with evidence gleaned from satellite imagery. Heritage advises that a conceptual lead E, previously carried in their prospect inventory, was postulated to be present in the southern part of Block 1. This area has since been covered by seismic data which resulted in the identification of the Buffalo prospect in the location of conceptual structure E, as well as three additional prospects being mapped using the new seismic data in that vicinity. Heritage’s estimated mean STOIIP for conceptual structure E was 804 million barrels. This has been replaced by four prospects carrying a mean unrisked STOIIP (100 per cent. basis) in excess of 2 billion barrels, as estimated by RPS. 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 south-western extremity of Block 3A. The prospective resources calculated by Heritage for these three structures are in Table 25:

113 RPS Energy Heritage Oil – Competent Persons Report

These evaluations are reported herein for completeness, but RPS does not warrant these estimates. Mean Unrisked STOIIP (100% basis) (MMstb) Block 3A Conceptual Structure D ...... 464 Block 1 Conceptual Structure F ...... 2,925 Conceptual Structure G ...... 2,925 Total of Mean ...... 6,314

Table 25: Heritage Conceptual Leads Mean Un-Risked STOIP (100 per cent. Basis) Not Reviewed by RPS)

5.7. Petroleum Engineering 5.7.1. Production Profiles for Kingfisher and Other Block 3A Prospects The Kingfisher well was tested in both the -1 and -1A well-bores; the former well-bore tested an isolated sand, so RPS have concentrated on the latter tests, which are summarised below, including results of the RPS independent well test analyses.

Interval Max Oil Rate Gas Rate Choke WHFP PTA Well DST (m MD) (stb/d) (MMscf/d) (‘‘) (psig) K (mD) S AP1 KF-1 ...... 1 2,344-2,339 2,965 64/64 238 206 2.4 27-32 2,361-2,367 (21 m interval) KF-1A ..... 2 2,302-2,290 2,533 0.363 64/64 157 414 2.1 31 (12 m interval) KF-1A ..... 3 2,260-2,271 4,669 0.363 64/64 130 2,380 1.2 32-33 (11 m interval) Table 26: Summary of Kingfisher-1A Well Tests

As can be seen, the reservoir quality is excellent, although there is a significant contrast between separate sands. The produced fluids from all these tests are similar, and fluid properties are summarised below. The GOR is low and the fluid is highly under-saturated, so a solution gas drive will not develop. ț Ȗ Depth pr Tr pb Boi Rsi Ȝ o DST Well (m MD) (psia) (oF) (psia) (rb/stb) (scf/stb) g/cm3 cp oAPI DST2...... KF-1 1,785.0 2,566 171 1,035 1.11 161 0.808 6.0 31.1 DST1...... KF-1A 2,355.5 316 187 1,285 1.17 263 0.790 4.0 31.1 DST2...... KF-1A 2,296.0 3,189 186 1,320 1.15 254 0.800 4.5 31.2 DST3...... KF-1A 2,265.5 3,148 186 1,255 1.15 221 0.793 3.5 31.1 Table 27: Summary of Kingfisher-1 Fluid Properties

The volumes in Block 3A are being categorised as either Contingent Resources or Prospective Resources at this stage of project maturity, and we have therefore used a number of assumptions to construct profiles for a highly conceptual development of Kingfisher, that would be ‘‘scalable’’ to similar prospects or leads in Block 3A. These assumptions are given in Table 28. 1P 2P 3P Recovery Factor ...... 20% 30% 40% Implied Resources(14) (MMstb) ...... 10 90 424 Recovery per well (MMstb) ...... 5 7.5 10 URR per year ...... 9% 9% 10% GOR (scf/stb) ...... 235 235 235 Table 28: Assumptions Used For Profiles

(14) This refers to Kingfisher only.

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The resulting profiles are shown in Figure 30, below.

140,000 450 Oil Rate (stb/d) Cumulative Oil (MMstb)

400 120,000

350

100,000

300 ) 80,000 250 MMstb (

200 60,000 Oil Rate (stb/d)

150 Cumulative Oil

40,000

100

20,000 50

0 0

8 0 2 4 6 8 0 2 4 28 0 32 34 36 8 0 42 4 200 201 201 201 201 201 202 202 202 2026 20 203 20 20 20 203 204 20 204 3P Rate 2P Rate 3P Rate 1P Rate 3P Cumulative 2P Cumulative 1P Cumulative22FEB200803434264 Figure 30: Generic, Scalable Profile for Block 3A Prospects

5.7.2. Production Profiles for Block 1 Prospects A similar approach was used to generate generic, scalable profiles for prospects & lads in Block 1, but we have made the assumption that recovery may be lower as a result of a potentially heavier oil at the much shallower depths. The profile (with STOIIP = 250 MMstb) is shown in Figure 31, below.

16,000 70 Oil Rate (stb/d) Cumulative Oli Rate (MMstb)

14,000 60

12,000 50

10,000 40

8,000

30 6,000

20 4,000

10 2,000

0 0

8 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 203 2040

Rate Cumulative 22FEB200803434419 Figure 31: Generic, Scalable Profile for Block 1 Prospects & Leads

115 RPS Energy Heritage Oil – Competent Persons Report

6. KURDISTAN—MIRAN BLOCK The Miran Block is located in the highly petroliferous Chemchemal-Butmah Embayment which forms part of the foothills adjacent to the NW-SE trending Zagros Fold Belt. The Miran Block lies about 60 km to the NE of the super giant Kirkuk oilfield.

6.1. Data Available Exploration of this area is at a very early stage. No seismic data have been acquired and no wells have been drilled in the block. A satellite image indicating surface topography plus a geological land-use interpretation based on satellite imagery were the only information available.

6.2. Geology The Miran Block encompasses the whole of the surface expression of the large undrilled Miran structure, which covers an area of about 700 sq km. This structure lies on trend and 40 km to the SE of the giant Taq Taq oilfield (currently under development) and about 20 km to the NE of the potentially large, but only lightly appraised, Chemchemal gas condensate discovery. The satellite image interpretation indicates that the Miran structure is an elongate anticlinal feature with a NW-SE trending fold axis parallel to the trend of the Zagros Fold Belt. By analogy with the Taq Taq field potentially productive horizons could be expected for the Late Cretaceous Shiranish and Kometan Formations and the Early Cretaceous Qamchuqa Formation. The Shiranish and Kometan Formations are both limestones with low porosity (<5 per cent.), but fracturing allows commercial flow-rates to be achieved. The Qamchuqa Formation is a dolomitic limestone that has up to 15 per cent. total porosity. Small volumes of oil were also found in the Eocene Pila Spi Formation at Taq Taq. The Chemchemal accumulation is reservoired in Eocene limestones (gas) and fractured Shiranish Formation limestones (gas and condensate).

6.3. In Place Volumes 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 of the block, made an estimate of a range of reasonable notional in place volumes in Miran as follows:

Notional STOIIP (MMstb) Low Mid High Matrix Porosity ...... 670 1,430 2,550 Fracture Porosity ...... 230 520 950 Total STOIIP ...... 900 1,950 3,500

Table 29: Miran Field—Range of Notional STOIIP

These volumes have then been used to develop cost and production profiles in order to develop a relationship between field size and value in the success case.

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6.4. Reservoir Engineering RPS has created production profiles for input to the Miran economics, based on our knowledge of the offset fields and other standard, petroleum engineering assumptions. The general assumptions used are given in Table 30.

Low Medium High Production Wells ...... 26 52 79 Dry hole wells ...... 3 5 8 Water Injection wells ...... 0 13 20 Total wells ...... 29 70 107 STOIIP (MMstb) ...... 909 1,963 3,511 in fracture (MMstb) ...... 236 533 954 in Matrix (MMstb) ...... 673 1,430 2,557 Recovery estimate ...... 60% of fracture only 60% of fracture + 70% of fracture + 15% of Matrix 20% of Matrix Reserves (MMstb) ...... 142 534 1179 Recovery Factor ...... 0.16 0.27 0.34 Peak field oil rate, bopd ...... 50,000 150,000 300,000 Ave cum/producer (MMstb/well) .... 5.4 10.3 14.9 Associated gas (Bscf) ...... 120 454 1,002 Peak field gas rate, MMscf/d ...... 45 130 260 Field life (years) ...... 25 30 30 Table 30: Assumptions Used in Miran Profiles

RPS has made the following additional assumptions in developing these profiles: — The maximum number of wells drilled per year is 10 wells for the low and medium cases, 20 wells for high case. The annual well effective decline rate is 26 per cent. for low case with initial well rate at 3,500 stb/d for 1 year, 18 per cent. for medium case with initial well rate at 4,000 stb/d for 2 years and 15 per cent. for high case with initial well rate at 4,500 for 3 years. These are compared with the previous work on similar fields case, with the assumption that production is from fractures only—initial, stabilised well rate at 5,000 stb/d for 3 years followed by an annual decline of 18 per cent. Depending on the development plan, in the medium and high cases, some gas injectors may be required. Recovery per well assumptions are: ~ 5 MMstb/well for the low case, ~10 MMstb/well for the medium case and ~15 MMstb/well for the high case (which gives the well count).

117 RPS Energy Heritage Oil – Competent Persons Report

The resulting individual well performance profiles are shown in Figure 32, below.

5000 15.0

4000 12.0

3000 9.0

2000 6.0

Low case Medium case

Average yearly oil rate (stb/d) 1000 High case 3.0 Cumulative oil production (MMstb)

0 0.0 0 5 10 15 20 25 30 Production year 22FEB200803434564 Figure 32: Assumed Well Profiles for Miran Wells

6.5. Facilities and Costs Based on a p50 recoverable volume of 534 MMstb RPS has assumed that a prospect could be tied into the Northern Iraq Pipeline System which is being planned by a consortium of Oil Companies and Government entities. The plan is to have several hubs and transfer stations so that any prospects/fields are within a range of 60km of the collection system. The cost of developing Miran would be in the order of S1.2 billion with operating costs expected to be US$100 MM/annum.

7. ECONOMICS 7.1. Valuation Assumptions 7.1.1. General The effective date of this report is 30/09/2007 and is used as the discount date for the valuation. All values are post-tax and have been expressed over a range of discount rates. An annual inflation rate of 2 per cent. has been assumed and is applied to both costs and revenues.

118 RPS Energy Heritage Oil – Competent Persons Report

7.1.2. Oil Prices The valuation has been based on a long term forecast for Brent as shown in Table 31 and Figure 32. This forecast represents RPS Energy’s base case forecast. A Low Price Case and High Price Case are also shown in the Table and have been used for price sensitivity purposes.

Low Price Case Base Price Case High Price Case (US$/bbl, MOD) (US$/bbl, MOD) (US$/bbl, MOD) 4Q 2007 ...... 88.6 88.6 88.6 2008 ...... 80.0 85.0 90.0 2009 ...... 73.0 82.0 91.0 2010 ...... 68.0 80.0 92.5 2011 ...... 62.0 78.0 95.0 2012 ...... 58.0 77.0 97.4 2013 ...... 55.2 77.3 99.4 2014 ...... 56.3 78.8 101.4 2015 ...... 57.4 80.4 103.4 2016 ...... 58.6 82.0 105.4 2017 ...... 59.8 83.7 107.6 2018 ...... 60.9 85.3 109.7 2019 ...... 62.2 87.0 111.9 2020 ...... 63.4 88.8 114.1 2021 ...... 64.7 90.6 116.4 2022 onwards ...... +2% p.a. +2% p.a. +2% p.a. Table 31: RPS Forecast Price Cases

These Low Base and High price forecasts represent US$50/bbl, US$70/bbl and US$90/bbl real long-term oil prices.

100.00

90.00

80.00

70.00

60.00

50.00 Brent ($/bbl) 40.00

30.00

20.00 Forecast price ($ MOD)

10.00 Forecast price ($ 2008)

0.00 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 201922FEB200803434712 2020 2021 Figure 32: RPS Base Forecast Price

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This forecast price was used as the basis for all other price forecasts required for the valuation. These prices are summarised in Table 32. Details of how each price deck was derived can be found in the sections below for each asset.

Oman Russia Kurdistan Oil Condensate LPG Gas Bukha/ Bukha/ Bukha/ West West West Urals West West Saudi Saudi Bukha Bukha Bukha Bukha Export Kirkuk Bukha NWS Bukha Propane Butane Propane Butane Gas Gas Blend Domestic Blend Year $/bbl $/bbl $/bbl $/tonne $/tonne $/tonne $/tonne $/MMBTU $/MMBTU $/bbl $/bbl $/bbl

2007 ...... 88.59 85.75 83.05 662.74 675.85 530.19 540.68 0.00 1.00 84.16 42.08 82.39 2008 ...... 85.00 82.35 79.65 640.97 653.51 512.77 522.81 0.00 1.00 80.75 40.38 79.05 2009 ...... 82.00 79.51 76.81 622.78 634.84 498.22 507.87 0.00 1.00 77.90 38.95 76.26 2010 ...... 80.00 77.62 74.92 610.65 622.39 488.52 497.91 0.00 1.00 76.00 38.00 74.40 2011 ...... 78.00 75.72 73.02 598.52 609.95 478.82 487.96 0.00 1.00 74.10 37.05 72.54 2012 ...... 77.00 74.77 72.07 592.45 603.72 473.96 482.98 0.00 1.00 73.15 36.58 71.61 2013 ...... 77.29 75.05 72.35 594.21 605.53 475.37 484.42 0.00 1.00 73.43 36.71 71.88 2014 ...... 78.83 76.51 73.81 603.55 615.11 482.84 492.09 0.00 1.00 74.89 37.44 73.31 2015 ...... +2%pa +2%pa +2%pa +2%pa +2%pa +2%pa +2%pa 0.00 1.00 +2%pa +2%pa +2%pa Table 32: Table of Base Case Forecast Prices

7.2. Valuation Methodology 7.2.1. Reserves 1P, 2P and 3P reserves were valued using spreadsheet based discounted cash flow models. Each model was based on the applicable contract terms and a forecast of future production and costs.

7.2.2. Contingent and Prospective Resources 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.

7.2.3. Other (Miran) In the case of the Miran Contract area in Kurdistan no prospect or lead has yet been properly defined. The valuation therefore involved illustrating the value of a number of notional fields on a recoverable volume vs. value plot as an indication of the potential value of success in this block.

7.3. Oman—Block 8 7.3.1. Fiscal Regime and Contract Terms The Block 8 Petroleum Agreement was signed in February 1985 and has a Development Period of 30 years from date of first commercial discovery. There is also an option to extend this for a further 10 years under terms to be negotiated which shall be no less favourable than those under which other oil companies are then operating in Oman. The extended details of the Block 8 PSC are subject to confidentiality agreements. However, RPS Energy confirms that it has had full access to the final, signed copy of PSC under the terms of such agreements and that the commercial terms therein have been built into our economics models. The RPS valuation honours fully these commercial terms. The commercial structure of the Block 8 PSC is in our opinion, very similar to standard PSC’s with the Contractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the total revenue) and Profit Oil (shared between the Contractor and the Government based on a fixed percentage of the revenue less any cost oil). There are no royalty payments due under the contract and the Contractor’s Income Tax liability is paid by the Government out of its share of Profit Oil.

7.3.2. Price Assumptions 7.3.2.1. Condensate The current Bukha condensate contract price for the current month is based on the average mean quotes of APPI NWS oil during the previous month plus the mean of the Platts NWS differential for the month

120 RPS Energy Heritage Oil – Competent Persons Report prior to that less a discount of US$2.70/bbl. A NSW forecast price was derived from the Brent forecast price using a relationship developed from a study of historical prices for both NWS and Brent. No contract price has yet been agreed for West Bukha condensate so this has been valued on the same basis as the current Bukha condensate contract.

7.3.2.2. Oil West Bukha oil has been valued assuming parity with the Brent forecast price.

7.3.2.3. Gas There are no gas sales from Bukha, but West Bukha gas has a contract gas price with RAKGAS of US$1/MMBTU when Saudi Light is above US$34/bbl.

7.3.2.4. LPG LPG’s (Propane and Butane) from Bukha are sold at 80 per cent. of the average price of Saudi Propane and Butane for the previous month less a 50 per cent. discount to account for RAKGAS share. It has been assumed that West Bukha LPG’s will be sold on the same basis.

7.3.3. Unrecovered Costs The total amount of unrecovered costs in Block 8 at 30/09/2007 stands at US$35.51 million. The majority of these costs however relate to the West Bukha development. For the valuation of Bukha on its own an estimate of 5 per cent. of the total was assumed as unrecovered costs. This estimate was provided by Heritage.

7.3.4. Valuation Summary—Bukha The post-tax valuation of the net Heritage share is shown in Table 33 at various discount rates.

Post-Tax Net Present Value Economic (US$ Million, Money of the Day) Net Heritage Share Limit(1) 5% 7.5% 10% 12.5% 15% Proved Reserves (1P) ...... 2029 2.2 1.7 1.4 1.2 1.0 Proved plus Probable Reserves (2P) ...... 2029 2.8 2.1 1.7 1.4 1.2 Proved plus Probable plus Possible Reserves (3P) ...... 2029 3.0 2.3 1.7 1.4 1.2

Note 1: Economic limit represents last year of input forecast production Table 33: Bukha Post-Tax Valuation (Net Heritage Share)

Bukha reserves are summarised in Table 34, below. Heritage Net Heritage Net Gross Working Entitlement Remaining Interest Reserves at Base Reserves Reserves Case Price Forecast (MMstb) (MMstb) (MMstb) Condensate Proved Reserves (1P) ...... 2.1 0.206 0.094 Proved plus Probable Reserves (2P) ...... 2.4 0.243 0.099 Proved plus Probable plus Possible Reserves (3P) ...... 2.6 0.260 0.102 LPG Proved Reserves (1P) ...... 1.5 0.151 0.035 Proved plus Probable Reserves (2P) ...... 2.2 0.225 0.046 Proved plus Probable plus Possible Reserves (3P) ...... 2.5 0.253 0.049 Table 34: Bukha Reserves Summary

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7.3.5. Valuation Summary—West Bukha The post-tax valuation of the net Heritage share is shown in Table 35 at various discount rates.

Post-Tax Net Present Value Economic (US$ Million, Money of the Day) Net Heritage Share Limit(1) 5% 7.5% 10% 12.5% 15% Proved Reserves (1P) ...... 2037 15.5 13.2 11.4 9.9 8.7 Proved plus Probable Reserves (2P) ...... 2037 39.9 35.1 31.3 28.3 25.7 Proved plus Probable plus Possible Reserves (3P) ...... 2037 79.7 68.6 60.2 53.6 48.3

Note 1: Economic limit represents last year of input forecast production Table 35: West Bukha Post-Tax Valuation (Net Heritage Share)

West Bukha reserves are summarised in Table 36, below. Heritage Net Heritage Net Gross Working Entitlement Remaining Interest Reserves at Base Reserves Reserves Case Price Forecast (MMstb) (MMstb) (MMstb) Oil Proved Reserves (1P) ...... 9.1 0.906 0.5280 Proved plus Probable Reserves (2P) ...... 20.7 2.1 0.764 Proved plus Probable plus Possible Reserves (3P) ...... 39.5 3.9 1.2 Condensate Proved Reserves (1P) ...... 3.9 0.390 0.195 Proved plus Probable Reserves (2P) ...... 8.0 0.794 0.275 Proved plus Probable plus Possible Reserves (3P) ...... 16.1 1.6 0.427 LPG Proved Reserves (1P) ...... 5.9 0.594 0.145 Proved plus Probable Reserves (2P) ...... 12.3 1.2 0.208 Proved plus Probable plus Possible Reserves (3P) ...... 25.4 2.5 0.339 Gas Proved Reserves (1P) ...... 7.4 0.736 0.510 Proved plus Probable Reserves (2P) ...... 47.5 4.8 1.5 Proved plus Probable plus Possible Reserves (3P) ...... 90.0 9.0 2.3 Table 36: West Bukha Reserves Summary

7.3.6. Sensitivity to Oil Price

Sensitivity of the NPV10 of the future net revenue in Bukha to changes in oil price is shown in Table 37.

Net Present Value10 of Future Net Revenue Price Case 1P 2P 3P (US$ Million, Money of the Day) Low Price ($50/bbl real) ...... 1.1 1.3 1.3 Base Price ($70/bbl real) ...... 1.4 1.7 1.7 High Price ($90/bbl real) ...... 1.7 2.1 2.2

Table 37: Sensitivity of Bukha NPV10 to Oil Price

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Sensitivity of the NPV10 of the future net revenue in West Bukha to changes in oil price is shown in Table 38.

Net Present Value10 of Future Net Revenue Price Case 1P 2P 3P (US$ Million, Money of the Day) Low Price ($50/bbl real) ...... 8.6 25.1 48.0 Base Price ($70/bbl real) ...... 11.4 31.3 60.2 High Price ($90/bbl real) ...... 14.3 37.7 72.6

Table 38: Sensitivity of West Bukha NPV10 to Oil Price

7.4. Russia—Zapadno Chumpasskoye 7.4.1. Fiscal Regime and Contract Terms The Zapadno Chumpasskoye licence is due to expire in September 2024. The main commercial terms are:

Crude Oil Export Duty

Urals Urals Rate ($/tonne) ($/bbl) <109.5 <15 0 109.5 - 146.0 15 - 20 0.35 * (P 15) 146.0 - 182.5 20 - 25 1.75 + 0.45 * (P 20) >182,5 >25 4.00 + 0.65 * (P 25) P = average quarterly price of Urals Blend (US$/bbl)

VAT ...... 18 per cent. on domestic sales Mineral Extraction Tax (MET) ...... OIL Jan 2005—September 2007 ...... MET = 419 Roubles / tonne * Cp Where Cp = (P 9) * (R / 261) P = average quarterly price of Urals Blend (US$/bbl) R = average quarterly exchange rate for US$/Rouble Assumed from September 2007 ...... 16.50 per cent. Tax base—Revenue less VAT, excise tax, custom duties, transportation costs and insurance costs Property Tax ...... 2.2 per cent. Tax base—Cumulative Capex (drilling and facilities) less depreciation Income / Profits Tax ...... 24.0% Tax base—Revenue less Opex, depreciation, interest, exchange rate losses and losses on re-evaluation. Depreciation: Facilities: 7-10 years Drilling: 10-15 years Pipelines: 20-25 years Loss carry forward—10 years

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7.4.2. Price Assumptions Heritage has assumed that the gross field production will be split between export (via Black Sea) and domestic sales in the proportion 35 per cent./65 per cent. respectively. The export price has been based on the Urals (Mediterranean) price. This has been derived from the Brent forecast using a relationship based on an analysis of historical prices. A 5 per cent. discount to Brent has been assumed for the valuation. The domestic price was assumed to be 50% of the Urals price.

$100.0

$90.0

$80.0

$70.0

$60.0

$50.0

$40.0 URALS (Mediterranean), $/bbl

$30.0

$20.0

$10.0

$0.0 $0.0 $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 $80.0 $90.0 $100.0 Brent ($/bbl) 22FEB200803435181 Figure 33: Plot of Brent vs. URALS (Mediterranean)—1997 to 2007

7.4.3. Transportation Costs Estimates of the transportation costs for export via the Transneft pipeline system and for domestic sales were provided by Heritage Oil and Gas. A figure of US$4.53/bbl was used for export costs and US$1.78/bbl for domestic transportation costs.

7.4.4. Tax Losses The total tax loss carry forward at 30/09/2007 of US$22.5 MM was included in the valuation as a deduction against future profits tax liabilities. This sum was provided by Heritage.

7.4.5. Valuation Summary Although the licence expiry date is 2024, the value and reserves have been reported up to their economic limit on the assumption that the licence will be extended full economic recovery of all the reserves. The valuation includes the cost of abandonment of the wells and all facilities, which has been estimated to be US$25.0 MM, US$40.0 MM and US$55.0 MM (in 2007US$) for the 1P, 2P and 3P cases, respectively.

Post-Tax Net Present Value Economic (US$ Million, Money of the Day) Limit(1) 5% 7.5% 10% 12.5% 15% Proved Reserves (1P) ...... 2025 69.1 40.2 17.5 0.2 32.9 Proved plus Probable Reserves (2P) ...... 2029 413.6 308.0 226.6 163.5 46.7 Proved plus Probable plus Possible Reserves (3P) . 2031 1356.2 1013.7 762.2 574.5 238.2 Table 39: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share)

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Zapadno Chumpasskoye reserves are summarised in Table 40, below. Heritage Net Heritage Net Gross Working Entitlement Remaining Interest Reserves at Base Reserves Reserves Case Price Forecast (MMstb) (MMstb) (MMstb) Oil Proved Reserves (1P) ...... 24.4 23.1 23.1 Proved plus Probable Reserves (2P) ...... 63.6 60.5 60.5 Proved plus Probable plus Possible Reserves (3P) ...... 169.9 161.4 161.4 Table 40: Zapadno Chumpasskoye Reserves Summary

7.4.6. Sensitivity to Oil Price

Sensitivity of the NPV10 of the future net revenue in Zapadno Chumpasskoye to changes in oil price is shown in Table 41.

Net Present Value10 of Future Net Revenue Price Case 1P 2P 3P (US$ Million, Money of the Day) Low Price ($50/bbl real) ...... 46.2 71.4 378.4 Base Price ($70/bbl real) ...... 17.5 226.6 762.2 High Price ($90/bbl real) ...... 80.6 383.0 1,150.0

Table 41: Sensitivity of Zapadno Chumpasskoye NPV10 to Oil Price

7.5. KURDISTAN—Miran Block 7.5.1. Fiscal Regime and Contract Terms The Miran Block was signed in October 2007. The exploration period is 5 years in duration and is subdivided into an initial sub-period of 3 years with the option of a second sub-period of 2 years. The development period lasts for an initial 20 years and can be extended for an additional 5 years. The extended details of the Miran PSC are subject to confidentiality agreements. However, RPS Energy confirms that it has had full access to the final, signed copy of PSC under the terms of such agreements and that the commercial terms therein have been built into our economics models. The RPS valuation honours fully these commercial terms. The commercial structure of the Block 8 PSC is in our opinion very similar to standard PSC’s with the Contractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the net revenue) and Profit Oil (shared between the Contractor and the Government based on a R factor, the R factor being defined as the ratio of cumulative revenue divided by cumulative costs). A royalty payment is due under the contract on gross production and net revenue is defined as the gross revenue less royalty. As is normal, the Contractor’s Income Tax liability is paid by the Government out of its share of Profit Oil. The Government may participate in any future development at a level of up to 25% at the point when commerciality is declared, but is not required to make any repayment to the Contractor for costs incurred up to that point.

7.5.2. Price Assumptions For the purposes of the valuation it was assumed that Miran crude would trade at a similar price as Kirkuk. This crude currently trades around 7 per cent. below Brent

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7.5.3. Valuation summary In the absence of any data upon which to assess the potential of the Miran contract area the range in possible value has been illustrated in the figure below. This plot demonstrates the possible range in unrisked NPV10 (net to Heritage) for a range of notional field sizes and could be used as an indicator of the possible value of the contract area. Curves are presented for a low and high oil price in addition to the Base Case price forecast.

$4,500

$4,000 High price ($90/bbl) Base price ($70/bbl)

$3,500 Low price ($50/bbl)

$3,000

$2,500

$2,000 Net to Heritage, MMUS$

10 $1,500

NPV $1,000

$500

$0 - 200 400 600 800 1,000 1,200

Gross Recoverable Oil, Economic Life of Contract, MMstb 28FEB200808431129

Figure 34: Heritage Net NPV10 vs. Notional Field Size Showing Price Sensitivity

Net NPV10 and average for NPV10c per barrel for the Base Case oil price forecast are given in Table 42 for the range of recoverable volumes based on the notional field sizes RPS has assumed.

Net NPV10 and Average for NPV10 /stb at Base Case Price Forecasts Low Case Mid Case High Case Gross Recoverable Oil Volume (MMstb) ...... 138 520 1,138

NPV10 Net to Heritage (US$MM) ...... 413 1,366 2,952 Average NPV10 /stb ...... US$2.6

Table 42: Net NPV10 and Average for NPV10 /stb for a Range of Notional Field Sizes

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APPENDIX A: GLOSSARY OF TECHNICAL TERMS 1P Proved 2P Proved plus Probable 3P Proved plus Probable plus Possible AAPG American Association of Petroleum Geologists API American Petroleum Institute B Billion Barg gauge pressure in Bar bbls barrels bopd barrels of oil per day

Bo(g)i initial formation volume factor for oil (or gas) Bscf billion standard cubic feet Btu British Thermal Units

(i/n)Cn (isomeric or normal) hydrocarbon of the general form CnH2n+2

C1 C1H4, methane

C3 C3H8, propane

C4 C4H10, butane

C7(+) C7H16, heptane (plus, meaning heptane and all heavier fractions)) CGR Condensate: Gas Ratio

CO2 carbon dioxide CoS Chance of Success CVD Constant Volume Depletion (a laboratory experiment) DST drill stem test Entitlement Volumes the volumes of oil and/or gas which a Contractor receives under the terms of a PSA EoS Equation of State FBHP flowing bottom hole pressure FFD Full Field Development ft Feet

FVF Formation Volume Factor (also: Boi) FWHP flowing well head pressure G&A General & Administrative GIIP Gas Initially In Place GOC Gas-oil contact GOR Gas: Oil Ratio GRV gross rock volume

H2S hydrogen sulphide LPG Liquefied Petroleum Gas—in this context means either Butane or Propane or both k(e) (effective) permeability kg kilogram km kilometre m metres M Thousand MD measured depth

127 RPS Energy Heritage Oil – Competent Persons Report mD permeability in milli-Darcies MM Million Mbbls thousand barrels MMBtu/d millions of British Thermal Units per day MMbwpd million barrels of water per day MMscfd or MMscf/d millions of standard cubit feet per day MMstb million stock tank barrels Money of the Day calculated allowing for the effect of inflation MPa Mega Pascal

N2 Nitrogen N:G Net to gross ratio NIOC National Iranian Oil Company OWC oil-water contact PI Productivity Index (stb/d/psi) p(b/r) (bubble point or reservoir) pressure PSC / PSA Production Sharing Contract / Production Sharing Agreement psi(a/g) pounds per square inch (absolute/gauge) PTA Pressure transient analysis PVT Pressure, Volume & Temperature RF Recovery Factor

Rsi Solution GOR

Rw Water resistivity S Skin, a measure of damage derived from well test analysis scf standard cubic feet measured at 14.7 pounds per square inch and 60 F SPE Society of Petroleum Engineers STOIIP Stock Tank Oil Initially In Place

Sw Water Saturation TD Total Depth

Tr Reservoir temperature TVD True vertical depth TVDSS true vertical depth (sub-sea) URR Ultimate recoverable reserves (before economic cut-off) VCL Volume of clay VRR Voidage replacement ratio VSH Volume of shale WHFP Wellhead Flowing Pressure Working Interest Share (of reserves) calculated by multiplying the Gross estimate by the Contractor’s Working Interest in a Production Sharing Contract WPC World Petroleum Congress ȉm Ohm-metre ȣ Omega, a measure of fracture storage ȕ Lambda, a measure of matrix-fracture flow țȜ Oil density Ȗș Oil viscosity

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APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS (Source: Society of Petroleum Engineers) The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project’s economic feasibility, its productive life, and its related cash flows

Petroleum Resources Classification Framework Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulphide and sulphur. In rare cases, non-hydrocarbon content could be greater than 50 per cent. The term ‘‘resources’’ as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered ‘‘conventional’’ or ‘‘unconventional.’’ A graphical representation of the SPE/WPC/AAPG/SPEE resources classification system is given below. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.

PRODUCTION

RESERVES

1P 2P 3P

Proved Probable Possible

CONTINGENT RESOURCES DISCOVERED PIIP DISCOVERED

1C 2C 3C

SUB-COMMERCIAL COMMERCIAL UNRECOVERABLE

PROSPECTIVE

RESOURCES Increasing Chance of Commerciality TOTAL PETROLEUM INITIALLY-IN-PLACE (PIP) INITIALLY-IN-PLACE PETROLEUM TOTAL

PIIP Low Best High Estimate Estimate Estimate

UNDISCOVERED UNRECOVERABLE

Range of Uncertainty 18MAR200800130115 Resources Classification Framework

129 RPS Energy Heritage Oil – Competent Persons Report

The ‘‘Range of Uncertainty’’ reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the ‘‘Chance of Commerciality’’, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification: TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to ‘‘total resources’’). DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage. Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below. RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub classified based on project maturity and/or characterized by their economic status. UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered. PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity. UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources). In specialized areas, such as basin potential studies, alternative terminology has been used; the total resources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total recoverable or

130 RPS Energy Heritage Oil – Competent Persons Report

EUR may be termed Basin Potential. The sum of Reserves, Contingent Resources, and Prospective Resources may be referred to as ‘‘remaining recoverable resources.’’ When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification.

Range of Uncertainty The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. When the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that: There should be at least a 90 per cent. probability (p90) that the quantities actually recovered will equal or exceed the low estimate. There should be at least a 50 per cent. probability (p50) that the quantities actually recovered will equal or exceed the best estimate. There should be at least a 10 per cent. probability (p10) that the quantities actually recovered will equal or exceed the high estimate. When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately.

Reserves Categories The following summarizes the definitions for each Reserves category in terms of both the deterministic incremental approach and scenario approach and also provides the probability criteria if probabilistic methods are applied. Proved Reserves (P1) are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 per cent. probability that the quantities actually recovered will equal or exceed the estimate. Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 per cent. probability that the actual quantities recovered will equal or exceed the 2P estimate. Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10 per cent. probability that the actual quantities recovered will equal or exceed the 3P estimate. Use of consistent terminology promotes clarity in communication of evaluation results. For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system. While the categorization criteria are proposed specifically for Reserves, in most cases, they can be equally applied to Contingent and Prospective Resources conditional upon their satisfying the criteria for discovery and/or development. For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. For Prospective Resources, the general cumulative terms low/best/high estimates still apply. No specific terms are defined for incremental quantities within Contingent and Prospective Resources.

131 PART IV—SELECTED FINANCIAL INFORMATION Set out below is the Group’s summary financial information for the periods indicated. As this is only a summary, investors are advised to read the whole of this document and not rely on the information summarised here.

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)

Net earnings per share from discontinued operations Basic and diluted ...... 0.16 0.57 0.11 —

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)

132 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 2005 2006 2006 2007 $$$$ (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 ...... — 914,558 — 4,200,909 69,973,627 89,443,027 89,458,028 149,053,091

133 Summary Consolidated Cashflow 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)

Summary Consolidated Income Statements (for financial years 2005 and 2004 prepared in accordance with Canadian GAAP and audited)

2004 2005 $$ 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 ...... 1.33 (0.18) Diluted ...... 1.31 (0.18)

134 Summary Consolidated Balance Sheets (at 31 December 2005 and 2004 prepared in accordance with Canadian GAAP and audited)

2005 2004 $$ Assets Current Assets Cash and cash equivalents ...... 8,583,321 16,235,523 Accounts receivable ...... 1,318,450 4,640,802 Note receivable ...... — 4,280,161 Inventories ...... 216,474 94,483 Prepaid expenses ...... 219,222 272,168 10,337,467 25,523,137 Property and equipment ...... 72,382,935 54,083,097 Deferred development costs ...... 1,187,371 1,013,012 83,907,773 80,619,246

Liability and Shareholders’ Equity Current Liabilities Accounts payable and accrued liabilities ...... 4,438,649 6,397,247 Current portion of long-term debt ...... 248,045 — 4,686,694 6,397,247 Long-term debt ...... 7,520,438 — Asset retirement obligations ...... 434,849 328,553 Shareholders’ Equity: Share capital and warrants ...... 22,854,418 21,434,168 Contributed surplus ...... 517,209 24,421 Retained earnings ...... 47,894,165 52,434,857 71,265,792 73,893,446 83,907,773 80,619,246

Summary Consolidated Cashflow Statements (for financial years 2005 and 2004 prepared in accordance with Canadian GAAP and audited)

2005 2004 $$ Cash used in operating activities ...... 697,123 1,866,009 Cash used in investing activities ...... (16,184,349) (11,310,312) Cash provided by financing activities ...... 9,020,147 604,953 Foreign exchange gains (losses) on cash held in foreign currency ...... (1,185,123) 906,001 Decrease in cash and cash equivalents ...... (7,652,202) (7,933,349) Cash and cash equivalents—beginning of year ...... 16,235,523 24,168,872 Cash and cash equivalents—end of year ...... 8,583,321 16,235,523

135 PART V—OPERATING AND FINANCIAL REVIEW The following discussion and analysis is intended to assist in the understanding and assessment of the trends and significant changes in the Group’s results of operations and financial condition. Historical results may not be indicative of future financial performance. Forward-looking statements contained in this review that reflect the current view of management involves risks and uncertainties and are subject to a variety of factors that could cause actual results to differ materially from those contemplated by such statements. Factors that may cause such a difference include, but are not limited to, those discussed in ‘‘Forward-Looking Statements’’ and ‘‘Risk Factors’’. In this document the consolidated financial statements presented are those of the Group. This discussion is based on the consolidated financial statements of the Group and should be read in conjunction with its consolidated financial statements and the accompanying notes contained in Part VI ‘‘Financial Information’’ and with the information relating to the business of the Group included elsewhere in this document. Unless otherwise indicated, all of the financial data and discussions thereof are based upon financial statements prepared in accordance with IFRS. Investors should read the whole of this document and not rely just on summarised information.

1. OVERVIEW The Company was incorporated on 6 February 2008. 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 interests in Africa, the Middle East, Russia and the Mediterranean. The Group has producing properties in Oman and Russia and exploration projects in Uganda, the KRI, the DRC, Malta, Pakistan and Mali.

Russia The Group has a 95 per cent. interest in a development project the Zapadno Chumpasskoye licence in Russia, which has proved and probable reserves of 60.5 million bbls net to the Group. Production commenced in May 2007, through well 226, which flowed clean oil typically between 300 and 400 bopd. Three wells have since been drilled of which one has been brought into production. Production averaged 342 bopd in February 2008. Planning of the design and specification of the field development facilities is ongoing.

Oman The Group has a 10 per cent. working interest in Block 8 in Oman. Block 8 includes Bukha, a producing gas-condensate field and West Bukha, an approved oil and gas development. In the last quarter of 2006, the West Bukha-2 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 and it is proposed to re-enter and complete it as a producing well. The oil was light (approximately 42o API). Development of the West Bukha field has commenced and comprises design, fabrication and installation of the wellhead platform and pipeline. Production is targeted for the third quarter of 2008. The West Bukha-3 production well is planned to be drilled in mid-2008.

Uganda The Group is the operator and has a 50 per cent. interest in two exploration licences in Uganda (Blocks 3A and 1). The Kingfisher deviated well in Block 3A was drilled to a total depth of 3,195 metres. Drilling was completed in March 2007. Four intervals were tested successfully in the Kingfisher well, resulting in an overall cumulative maximum flow rate of 13,893 bopd. The test produced quality light (between 30 and 32 API) and sweet oils with a low gas-oil ratio and some associated wax. The sandstone reservoirs exhibit high permeability up to 3,000 milliDarcies. The Kingfisher-2 well is scheduled to spud in the first half of 2008. Blocks 3A and 1 include minimum drilling and seismic commitments which the Group expects to achieve in 2008.

DRC The Group signed a PSC in the DRC in the summer of 2006 for a 39.5 per cent., non-operated interest in Blocks 1 and 2 covering over 6,000 square km of onshore and offshore acreage in the DRC part of the Albert Basin. An exploration programme, the timing of which is uncertain, will only commence following a presidential decree ratifying the DRC PSC. The minimum work programme in the DRC PSC for the two

136 blocks during the first three and a half year term includes the acquisition of 2D seismic and the drilling of two exploration wells, at a minimum gross cost of more than $10.275 million. The exploration term commences on receipt of the presidential decree.

KRG The Group has 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. Under the terms of the agreement, Heritage Middle East, a wholly-owned subsidiary of the Company, will serve as operator. The Miran licence area is 1,015 square km and encompasses a structure as expressed at surface which constitutes an area of approximately 500 square km and appears to have three separate culminations. Reservoir potential exists at numerous zones that management estimate could contain significant quantities of oil. The minimum work programme in the PSC during the first three year term comprises the acquisition of 2D seismic and the drilling of one exploration well, at a minimum cost of more than $8.5 million.

Mali The Group farmed-in to two onshore exploration licences in Mali, in North-West Africa, with a gross area of over 72,000 square km in November 2007. The Group has been appointed as operator. The Group has the right to acquire a 75 per cent. working interest in each of Block 7 and Block 11 from Centric Energy Corporation in return for funding the working interest. The Group will fund all costs of the obligatory work programmes for the next two years in both blocks, comprising the acquisition of 2D seismic and the drilling of one exploration well, at a total estimated cost for the two licences of between $15 million and $20 million.

Malta The Group was awarded 100 per cent. of Areas 2 and 7 offshore to Malta in December 2007. The licence areas encompass almost 18,000 square km and are situated approximately 80 km (Area 2) and 140 km (Area 7) from the Maltese coast in water depths ranging from between 80 metres and 300 metres. The minimum work programme in the PSC during the first three year term comprises the acquisition of 2D seismic and the drilling of one exploration well, at a minimum cost in excess of $22 million.

Pakistan A wholly-owned subsidiary of the Group was awarded a 60 per cent. participating interest in the Sanjawi Block (No. 3068-2) in Zone II (Baluchistan), in 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. The Group has been appointed operator. The joint venture partners are two companies incorporated in Pakistan, Sprint Energy (Pvt) Limited, a subsidiary of the JS Group, and Trakker Energy (Pvt) Limited.

2. ACQUISITIONS, DISPOSALS AND FINANCING The Group’s portfolio and financial position has changed in several material aspects over the last three years, including the following principal changes.

Year Ended 31 December 2004 In 2004, the Group was awarded a 50 per cent. working interest in Blocks 3A and 1 in the Albert Basin in Uganda, and was appointed operator in both blocks. Block 3A, which ordinarily encompassed most of the exploration acreage which previously constituted Block 3, which had been awarded in 1997 and after drilling three test wells at the same Turaco drill site, which were not considered commercial discoveries, it was subsequently relinquished, was re-licensed in 2004 for a term of six years and now covers an area of 2,033 square km. Block 1 licence covers an area of 3,659 km. On 9 June 2004, the Group sold a call option for proceeds of $1.2 million entitling the purchaser to acquire the overriding royalty in the Congo for proceeds of $30.4 million by 30 July 2004. An additional contingent consideration of up to A8.3 million (approximately $10 million) was payable on the sale of all or a portion of the interest by the purchaser by 31 December 2005, although this did not take place. Concurrent with the exercise of the option, the purchaser would be required to sell a seven per cent. working interest in

137 another oil and gas interest in the Congo to the Group for $7 million. The purchaser exercised its option on 30 June 2004. In 2003, the Group acquired a 33 per cent. interest in Pipelay and Naturalay Technologies and on 24 September 2004, acquired an additional 31.7 per cent. interest. Pipelay is a technology company whose purpose is to hold and market technology relating to the Buoyant Drum Lay System. Patent protection for the design has been secured and is held in Pipelay’s sister company, Naturalay Technologies. This system comprises a vessel, with a large drum floating in a moon pool.

Year Ended 31 December 2005 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 and production permit previously held by TNK-BP. The licence, which expires on 7 September 2024, is located in West Siberia in the province of Khanty-Mansiysk. A total of nine wells had been drilled on the licence prior to the acquisition by the Group. The licence is located in an extremely hydrocarbon-rich province close to well-developed infrastructure; a federal oil pipeline runs through the licence to which the Group has certain access rights and there is railway access nearby.

Year Ended 31 December 2006 In 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, a term of five years and one day and were convertible into HOC Common Shares at a price of $18 per share. HOC had the right 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. A total of 50 of the unsecured convertible bonds, with a total par value of $5 million, were converted into HOC Common Shares at an exercise price of $18 per share subsequent to 31 December 2006. The Group signed a PSC in the DRC in the summer of 2006 for a 39.5 per cent. interest in Blocks 1 and 2 in the prospective Albert Basin. Blocks 1 and 2 cover in excess of 6,000 square km over the onshore and offshore acreage in the DRC part of the Albert Basin that extends into neighbouring Uganda. The Kingfisher deviated well in Block 3A in Uganda spudded in August 2006 and drilled to a total depth of 3,195 metres. 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. Drilling and testing were completed in March 2007. In the last quarter of 2006, the Group entered into an agreement with TISE Holding Company to establish a jointly owned company, TISE-Heritage Neftegas, 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 million, plus 1.5 million 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.

Period ended 30 September 2007 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 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; 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 9 March 2007, the Group disposed of its 65 per cent. equity interests in Pipelay and Naturalay Technologies to Grove Holdings Limited for consideration of 605,000 common shares in SeaDragon. SeaDragon, founded in 2006, is building two semi-submersible rigs.

138 On 2 October 2007, the Group executed a PSC with the KRG over the Miran Block in the southern part of the KRI and a separate strategic agreement under which the Group will be a 50/50 partner with the KRG in designing and building a 20,000 bopd oil refinery in the vicinity of the licence area. Under the terms of the agreement, Heritage Middle East, a wholly-owned subsidiary of the Group, was appointed operator. 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 holds a 60 per cent. participating interest in the Sanjawi Block (No. 3068-2) in Zone II (Baluchistan) and was appointed as operator. On 17 November 2007, the Group farmed-in to two onshore exploration licences in Mali, in North-West Africa, with a gross area of over 72,000 square km. The Group has been appointed as operator. Wholly- owned subsidiaries of the Group have the right to acquire a 75 per cent. working interest in Block 7 and Block 11 from Mali Oil Developments SARL, a wholly-owned subsidiary of the public company Centric Energy Corporation. On 14 December 2007, the Group executed a PSC with the Maltese Government for Areas 2 and 7 in the southeastern offshore region of Malta. Under the terms of the agreement, Heritage Oil International Malta Limited, a wholly-owned subsidiary of the Group, will serve as operator with a 100 per cent. interest. The Group has financed the above acquisitions and work programmes during the period under review through the disposal of its interests in the Congo and two rounds of convertible bond issues and an equity financing. On 16 February 2007, HOC raised $165 million by completing the private placement of convertible bonds. HOC issued 1,650 unsecured convertible bonds, at par value of $100,000, which have a term of five years and one day and an annual coupon of 8 per cent. 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, although this right was not exercised. Proceeds were partly used to finance the redemption of the outstanding $55 million of convertible bonds at a premium of 150 per cent. 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 2007. On 14 November 2007, HOC completed an equity financing, raising gross proceeds of Cdn $181.5 million from the issue of 3 million HOC Common Shares by way of a private placement with institutional investors.

3. KEY FACTORS AFFECTING THE GROUP’S RESULTS OF OPERATIONS AND FINANCIAL CONDITION The key factors affecting the Group’s results of operations and financial condition during the periods under review and that the Group expects will continue to have a significant effect on its results of operations and financial condition in the future, include amongst others, the following: Exploration and development expenditure and success rates; Factors associated with operating in developing countries, political and regulatory instability; Oil and gas sales volumes and prices; and Reliance on key employees.

Exploration and development expenditure and success rates Oil and gas exploration involves a high degree of risk and 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 or at all. The principal expenditures related to the Group’s exploration work programmes are the acquisition of seismic data and the drilling of wells. When entering a new geological province and when drilling a new exploration prospect, the Group assesses the exploration risk involved and offsets that risk against the potential monetary gain in the event of success. The Group also reduces the potential risk by undertaking thorough exploration work as well as, in certain instances, exploring in known hydrocarbon provinces.

139 Factors associated with operating in developing countries, political and regulatory instability Certain of the Group’s 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. Wherever it operates the Group assesses all the significant operational challenges involved and plans accordingly. These challenges include technical, operational, logistical, social, environmental and political, and the Group draws upon the experience of its management and staff to address these issues. Additionally, risks are mitigated by forming strategic alliances in certain territories as well as employing local labour.

Oil and gas sales volumes and prices Both oil and gas prices are unstable and are subject to fluctuation and subject to various factors beyond the Group’s control. The Group can use derivative instruments to mitigate against its exposure to volatility in oil prices. However, during the years ended 31 December 2005, 31 December 2006 and the nine-month period ended 30 September 2007 the Group did not enter into any hedging arrangements.

Reliance on key employees The recruitment and retention of skilled personnel has become a key issue for the oil and gas industry, with significant competition existing for skilled personnel. Skilled personnel are required in the areas of exploration and development, operations, engineering, business development, oil and gas marketing, finance and accounting. The Company attracts staff by a combination of providing an excellent working environment and challenging and satisfying work, with a competitive remuneration package. The Company is therefore able to attract and retain high quality staff. The Group has a number of strategies in place for reinforcing its capabilities, including training and developing local skills and for example has entered into a number of scholarship schemes in Uganda.

4. OPERATIONAL PERFORMANCE Producing assets Oil and gas revenue was generated from the Group’s 10 per cent. working interest in the Bukha field, in Block 8, Oman, during the years ended 31 December 2005 and 2006 and the nine-month period ended 30 September 2007. The Bukha field produces gas, for which the Group derives no revenue, condensate and LPG. The Group’s average net share of liquids (condensate and LPG) has varied from between 140 and 172 bopd during the period under review. The development of the West Bukha field in Block 8, Oman continues to advance. Field development is ongoing and production from the West Bukha field is expected by management to commence in the third quarter of 2008. Crude oil production from the Zapadno Chumpasskoye field in Russia commenced on 14 May 2007 and averaged 362 bopd in the four months ended 30 September 2007. Production averaged 342 bopd in February 2008.

Exploration and appraisal assets The Group has experienced considerable exploration success in Uganda and work programmes have been accelerated following the discovery of a new hydrocarbon system in the Albert Basin. This discovery includes the Kingfisher-1 discovery well that was completed in March 2007, which production tested at rates of approximately 13,900 bopd. 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 2008. The Kingfisher appraisal drilling programme is scheduled to commence in the first half of 2008. Management expects this land rig to have the capability to reach the depth of the primary target horizon not reached by previous Kingfisher drilling. A 2D seismic survey is also being carried out on in Block 1, Uganda, 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 located within the block at Paraa. This oil seep together with the presence

140 of amplitude anomalies, further supports the potential presence of hydrocarbons within the block. An exploration drilling programme is scheduled to commence in or after the summer of 2008, concentrated on the shallower targets in the southern part of the block. In October 2007, the Group announced that it had executed a PSC with the KRG over the Miran Block in the southern part of the KRI. 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.

New projects Over the last six months the Group has expanded its portfolio by obtaining the right to acquire a 75 per cent. interest in two exploration licences in Mali, a 60 per cent. working interest in an exploration licence in Pakistan and a 100 per cent. interest in two licences offshore to Malta. The Group has been appointed as operator of these licences.

5. RESULTS OF CONTINUING OPERATIONS FOR THE GROUP FOR THE NINE-MONTH PERIOD ENDED 30 SEPTEMBER 2006 AND 2007 PREPARED IN ACCORDANCE WITH IFRS 5.1 Group Results The following table sets forth the Group’s results for the nine-month periods ended 30 September 2006 and 2007 prepared in accordance with IFRS.

Nine-month periods ended 30 September 2006 2007 $$ (Unaudited) Revenue Petroleum and natural gas ...... 2,984,091 2,843,053 Drilling services ...... 2,491,339 — 5,475,430 2,843,053

Expenses Petroleum and natural gas operating ...... 516,868 1,814,335 Drilling rig operating ...... 1,912,123 38,360 General and administrative ...... 5,446,010 31,331,031 Foreign exchange losses (gains) ...... 449,507 (76,493) Depletion, depreciation and amortisation ...... 948,477 1,306,131 Exploration expenditure ...... 3,373,024 4,937,595 Impairment of property, plant and equipment ...... — 1,799,762 12,646,009 41,150,721 Gain on disposal of subsidiaries ...... — 1,077,132 Finance income (costs) Interest income ...... 985,353 1,243,305 Loss on redemption of convertible bonds ...... — (7,155,622) Loss on derivative liability relating to convertible bonds ...... (5,483,503) (17,350,077) Other finance costs ...... (3,266,497) (7,052,903) Unrealised gain on other financial assets ...... — 63,351 (7,764,647) (30,251,946)

Loss from continuing operations ...... (14,935,226) (67,482,482) Income from discontinued operations ...... 2,417,316 —

Net loss for the period attributable to equity holders of the Corporation . . . (12,517,910) (67,482,482)

141 5.2 Petroleum and Natural Gas Production The Group’s net production in bopd from continuing operations is analysed below.

Nine-month periods ended 30 September Average net production 2006 2007 Bopd Bopd (Unaudited) Oman Condensate ...... 108 89 LPG...... 64 58 172 147

Russia Oil...... — 175 Total ...... 172 322

Net daily condensate and LPG production from the Bukha field, Block 8, Oman varied between 140 and 172 bopd during the period under review. Overall, gross field production of liquids declined by 14 per cent. to 1,618 bopd from the beginning to the end of the period, which was offset partly by an increase in the Group’s share of production resulting from higher cost recoveries from the drilling of the West Bukha well which spud in May 2006. Crude oil production from the Zapadno Chumpasskoye field in Russia commenced on 14 May 2007 and averaged 362 bopd in the three months ended 30 September 2007.

5.3 Petroleum and Natural Gas Revenue Petroleum and natural gas revenue may be analysed as follows.

Nine-month periods ended 30 September 2006 2007 $$ (Unaudited) Oman Condensate ...... 2,676,230 1,556,610 LPG...... 307,861 301,904 Russia Oil...... — 984,539 2,984,091 2,843,053

Petroleum and natural gas revenue from Oman in the nine-month period ended 30 September 2007, of $1,858,514 was 38 per cent. lower than the same period in 2006 as a result of the periodic sale of condensate from inventory. Condensate production from the Bukha field, Oman was sold to Sumitomo Corporation during the period under review. Petroleum and natural gas revenue from Russia from the sale of 46,688 bbls of crude oil in the nine-month period ended 30 September 2007 was $984,539. There was no third party drilling revenue in the nine-month period ended 30 September 2007 compared with $2,491,339 in the same period in 2006. Drill rig revenue is generated from the Group’s 50 per cent. share of Eagle Drill’s sales to third parties. In 2006, Eagle Drill was the drilling contractor for the operator of Block 2 in Uganda.

5.4 Operating Expenses Petroleum and natural gas operating costs in the nine-month period ended 30 September 2007 were $1,814,335 as compared to $516,868 for the same period in 2006.

142 The increase in operating expenses of $1,297,467 is mostly due to the operating expenses relating to production in Russia which commenced in May 2007. Operating expenses from drilling operations of $1,912,123 in the nine-month period ended 30 September 2006, were substantially higher than for the nine-month period ended 30 September 2007 due to the large increase in third party drilling operations in that year. Drilling rig operating expenses in the nine-month period ended 30 September 2007 were $38,360. The average operating cost per barrel sold during the period under review from the Bukha field in Oman may be summarised as follows:

Nine-month periods ended 30 September 2006 2007 $/bbl (1) $/bbl (1) (Unaudited) Average operating cost per barrel ...... 9.02 12.11 (1) As a result of the periodic nature of condensate sales from the Bukha field, Oman, $/bbl is based on net sales volumes rather than net production volumes.

5.5 General and Administrative General and administrative expenses increased from $5,446,010 in the nine-month period ended 30 September 2006 to $31,331,031 in the same period of 2007. This increase arose principally from higher stock-based compensation expenses relating to the conditional stock options granted in December 2006 under the new stock option plan approved by shareholders at the Annual Meeting of HOC in June 2007. If stock-based compensation expenses are excluded, net general and administrative expenses for the nine-month period ended 30 September 2007 were $8,271,491 as compared to $5,004,756 in the same period of 2006. This increase resulted from the following factors: Growth of the Group. The Group has employed additional staff and has appraised and undertaken operations in new territories during the period under review; Increased travel expenses in part due to the higher level of activity in the Group’s core areas; and In 2006 the Group trained 40 officials from the Ministry of Oil of Iraq and the Ministry of Natural Resources in Portugal at a cost of $720,000. A previous training course was undertaken in 2004, whilst no training courses were held in 2007. In the nine-month period ended 30 September 2007, the Group capitalised $10,410,894 (2006—$1,091,640) of general and administrative costs relating to exploration and development activities, including stock-based compensation of $8,957,752 (2006—nil).

5.6 Depletion, Depreciation and Amortisation

Nine-month periods ended 30 September 2006 2007 $$ (Unaudited) Depletion, depreciation and amortisation Petroleum and natural gas assets ...... 541,171 593,869 Drilling rig ...... 134,612 — Other corporate assets ...... 272,694 712,262 Total ...... 948,477 1,306,131

Depletion, depreciation and amortisation expenses increased by $357,654 from $948,477 in the nine-month period ended 30 September 2006 to $1,306,131 in the same period of 2007. This increase is principally due to the higher carrying value of the Oman property, plant and equipment subject to depletion and additional depreciation on corporate assets acquired in 2006 and the first half of 2007, offset by a reduction in depreciation of the drilling rig following a decrease in drilling activity.

143 5.7 Exploration Expenditure Exploration expenditure increased from $3,373,024 in the nine-month period ended 30 September 2006 to $4,937,595 in the same period in 2007. This increase in costs reflected the increased activity of the Group and costs incurred in new territories prior to a licence being awarded. Exploration expenditure in nine-month period ended 30 September 2006 principally related to costs in the KRI, whilst in the same period in 2007 related mainly to the KRI and potential new ventures in Russia.

5.8 Impairment of property, plant and equipment The carrying value of the drilling rig was written down to its estimated fair value. This resulted in an impairment write-down of $1,799,762 recognised in the income statement during the nine-month period ended 30 September 2007.

5.9 Gain on Disposal of Subsidiaries The Group recognised a gain on disposal of its subsidiaries of $1,077,132 in the first quarter of 2007. On 9 March 2007, the Group disposed of its 65 per cent. equity interests in Pipelay and Naturalay Technologies for consideration of 605,000 common shares in SeaDragon. The fair value of the common shares consideration received of $2,420,000, which was based on the most recent private placement to arms-length parties, resulted in a gain on the disposal of $1,077,132.

5.10 Finance Income (Costs) In the nine-month period ended 30 September 2007, interest income of $1,243,305 was $257,952 higher than in the same period in the previous year as a result of both average higher cash balances and higher average interest rates. Cash and cash equivalents are typically held in interest-bearing treasury accounts. Invested cash generating this income was raised by the issue of the $60 million and $165 million unsecured, convertible bonds in March 2006 and February 2007, respectively. Other finance costs increased by $3,786,406 from $3,266,497 in the nine-month period ended 30 September 2006, to $7,052,903 in the same period of 2007, as a result of the issuance of $60 million unsecured convertible bonds in March 2006 and $165 million unsecured convertible bonds in February 2007, which lead to higher interest and accretion expenses that are expensed to finance costs. On 17 January 2007, the Group 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 2007. This resulted in the recognition of a loss of $7,155,622 on the redemption, net of transaction costs, on the recorded liability and derivative liability in the nine-month period ended 30 September 2007. Convertible bonds were separated into liability and derivative liability components (being the bondholders’ conversion option) and each component is recognised separately. The change in the fair value of the convertible bonds conversion options which is primarily due to the increase in share price, resulted in a loss of $5,483,503 in the nine-month period ended 30 September 2006 and a loss of $17,350,077 in the nine- month period ended 30 September 2007. In the nine-month period ended 30 September 2007, the Group recognised an unrealised gain in the fair value of investment in warrants of $63,351. This relates to the Group’s holding of 1,500,000 warrants in Afren received as partial consideration from the sale of Heritage Congo in 2006.

144 5.11 Discontinued Operations The results of operations in Congo have been classified as earnings from discontinued operations. The following table provides additional information with respect to the amounts included in the earnings from discontinued operations. Period ended 30 September 2006 $ Revenue Petroleum and natural gas ...... 3,805,505 Other ...... 679,543 4,485,048 Expenses Petroleum and natural gas operating ...... 653,344 Royalties ...... 570,826 Depletion, depreciation and amortisation ...... 843,562 2,067,732 2,417,316

5.12 Net Loss for the Periods The net loss in the nine-month period ended 30 September 2007 was $67,482,482, compared to $12,517,910 in the same period in 2006. In the nine-month period ended 30 September 2007, the basic and diluted loss per share from continuing operations and net basic and diluted loss per share were $3.02, compared to basic and diluted loss per share from continuing operations of $0.68 and the net basic and diluted loss of $0.57 in the same period in 2006.

5.13 Capital Expenditures The following table sets out capital expenditures for the nine-month periods ended 30 September 2006 and 2007: Nine-month periods ended 30 September 2006 2007 $$ (Unaudited) Uganda Drilling ...... 5,327,637 7,814,808 Seismic ...... — 12,720,495 Other ...... 1,171,610 1,543,342 6,499,247 22,078,645

Oman Drilling ...... 2,621,614 749,862 Seismic ...... 332,192 88,897 Other ...... 233,115 1,982,649 3,186,921 2,821,408

Russia Drilling ...... — 5,590,214 Seismic ...... 1,373,001 — Other(1) ...... 4,338,516 8,645,083 5,711,517 14,235,297

145 Nine-month periods ended 30 September 2006 2007 $$ (Unaudited) Other Undeveloped lands ...... 16,892 713,068 Drilling equipment ...... 768,139 — Other equipment ...... — 11,638,997 Corporate ...... 1,437,206 119,906 2,222,237 12,471,971

Total from continuing operations ...... 17,619,922 51,607,321

Congo (discontinued operations): Drilling ...... 1,234,070 — Seismic ...... 205,262 — Other ...... 1,954,645 — 3,393,977 — Total capital expenditures ...... 21,013,899 51,607,321

(1) Such figure includes the acquisition costs of the licence in 2005.

Additions to property, plant and equipment in the nine-month period ended 30 September 2007 were $51,607,321, compared to $21,013,899 in the same period in the previous year. The following work was undertaken in the nine-month period ended 30 September 2007. (i) In Uganda, work programs have been accelerated following the discovery of a new hydrocarbon system in the Albert Basin. This discovery includes the Kingfisher-1 discovery well in 2007, which production tested from shallow horizons at rates of approximately 13,900 bopd. 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 2008. (ii) In Uganda, a circa 325 square km 3D seismic survey was carried out over the Kingfisher and neighbouring Pelican structures in Block 3A during the summer of 2007. Initial interpretation of the 3D seismic survey confirms that the Kingfisher structure has an aerial of up to approximately 45 square km. (iii) Also, a circa 530 km 2D seismic acquisition programme has just been completed in Block 3A in Lake Albert. This most recent programme supplemented previously acquired 2D surveys and covered previously un-surveyed areas of Lake Albert in order to identify additional drilling targets. (iv) A 2D seismic programme was acquired in Block 1, Uganda where relatively shallow structures have been identified with associated amplitude anomalies. (v) In the Zapadno Chumpasskoye field in Russia, the second well of the appraisal/exploration programme, well P2, was drilled and cased during the summer and sidetracked to be used as a producer in the field development project. (vi) The development of the West Bukha field in Block 8, Oman continued during the nine-month period ended 30 September of 2007.

146 6. RESULTS OF CONTINUING OPERATIONS FOR THE YEARS ENDED 31 DECEMBER 2005 AND 2006 PREPARED IN ACCORDANCE WITH IFRS 6.1 Group Results The following table sets forth the Group’s results for the years ended 31 December 2005 and 2006 prepared in accordance with IFRS.

Year ended Period ended 31 December 12 December 2005 2006 $$ Revenue Petroleum and natural gas ...... 841,766 3,938,512 Drilling services ...... 342,359 2,895,727 1,184,125 6,834,239

Expenses Petroleum and natural gas operating ...... 465,110 723,611 Drilling rig operating ...... 196,804 2,291,585 General and administrative ...... 5,706,396 8,628,127 Foreign exchange losses ...... 1,170,906 627,005 Depletion, depreciation and amortisation ...... 738,630 1,351,987 Exploration expenditure ...... 4,517,411 6,066,977 12,795,257 19,689,292

Finance income (costs) Interest income ...... 330,290 1,336,351 Loss on derivative liability relating to convertible bonds ...... — (24,851,295) Other finance costs ...... (491,824) (4,642,126) Unrealised gain on other financial assets ...... — 195,178 (161,534) (27,961,892) Loss from continuing operations ...... (11,772,666) (40,816,945) Gain on disposal of discontinued operations ...... — 9,200,700 Earnings from discontinued operations ...... 3,510,441 3,248,490 Income from discontinued operations ...... 3,510,441 12,449,190 Net loss for the period attributable to equity holders of the Corporation . . . (8,262,225) (28,367,755)

The Group completed disposition agreements for the sale of its remaining petroleum and natural gas interests in the Congo in 2006. The results of operations in the Congo have been classified as results of discontinued operations during the period under review and the related net assets classified as assets and liabilities of discontinued operation.

6.2 Petroleum and Natural Gas Production

Year ended 31 December Average net production 2005 2006 Bopd Bopd Oman Condensate ...... 69 105 LPG...... 71 64 140 169

Average net production from the Bukha field, Oman increased from 140 bopd in 2005 to 169 bopd in 2006, due to an increase in the Group’s share of production resulting from higher cost recoveries from the drilling of the West Bukha well which spud in May 2006. Overall, gross field production of liquids declined by 11 per cent. to 1,833 bopd in 2006, which was in line with expectations for this mature asset.

147 6.3 Petroleum and Natural Gas Revenue Petroleum and natural gas revenue may be analysed as follows.

Year ended 31 December 2005 2006 $$ Oman Condensate ...... 468,816 3,535,267 LPG...... 372,950 403,245 Total ...... 841,766 3,938,512

Net petroleum and natural gas revenue from Oman increased by $3,096,746 (368 per cent.) in 2006 to $3,938,512. $2,208,665 of this increase resulted from a 128 per cent. increase in sales volumes as a result of the periodic nature of condensate sales and $888,081 from a 106 per cent. increase in the weighted average commodity prices. The average sales price per barrel increased from $24.51 in 2005 to $50.36 in 2006.

6.4 Drilling Services Revenue Third party drilling rig revenue of $2,895,727 in 2006 was generated from the Group’s 50 per cent. share of Eagle Drill’s sales to third parties. Eagle Drill had drilled four wells and tested two wells in Block 2, Uganda since December 2005. Revenue in 2005 totalled $342,359.

6.5 Operating Expenses Petroleum and natural gas operating costs increased from $465,110 in 2005 to $723,611 in line with the volume of condensate sold from the Bukha field in Oman. Operating expenses from drilling operations of $2,291,585 in 2006, were substantially higher than the $196,804 incurred in 2005 due to the large increase in third party drilling operations in that year. The average operating cost per barrel sold during the period under review from the Bukha field, Oman may be summarised as follows.

Year ended 31 December 2005 2006 $/bbl (1) $/bbl (1) Average operating cost per barrel ...... 13.54 9.25

(1) As a result of the periodic nature of condensate sales from the Bukha field, Oman, $/bbl is based on net sales volumes rather than net production volumes.

6.6 General and Administrative General and administrative expenses increased from $5,706,396 in 2005 to $8,628,127 in 2006. The increase may be analysed as follows: In 2006 the Group trained 40 officials from the Ministry of Oil of Iraq and the Ministry of Natural Resources in Portugal at a cost of $720,000. A previous training course was undertaken in 2004, whilst no training was held in 2005; and The Group continued to grow substantially in 2006, employing additional staff, appraising and undertaking operations in new territories. The Group’s increased level of activity during 2006 can generally be linked to the acquisition of the Zapadno Chumpasskoye field in Russia, preparation for drilling in Uganda and initiatives in the KRI. Fees and expenses paid to technical members of staff and consultants increased by $1,530,000 in 2006, accounting for the majority of the remaining increase of $2,201,731. In 2006, the Group capitalised $2,813,303 (2005—$1,332,363) of general and administrative costs relating to exploration and development activities.

148 6.7 Foreign Exchange Losses There was a foreign exchange loss in 2006 of $627,005, primarily as a result of the strengthening of the pound sterling against the U.S. dollar, as the Group’s loan secured on the technical services office in London is a sterling-denominated loan. The technical services office in London is not revalued for exchange rate purposes, but acts as a natural hedge against adverse movements in exchange rates with this loan. The majority of the Group’s business is transacted in U.S. dollars and, accordingly, the Group’s functional and reporting currency is U.S. dollars.

6.8 Depletion, Depreciation and Amortisation

Year ended 31 December 2005 2006 $$ Depletion, depreciation and amortisation Petroleum and natural gas assets ...... 441,355 807,424 Drilling rig ...... — 176,013 Other corporate assets ...... 297,275 368,550 Total ...... 738,630 1,351,987

Depletion, depreciation and amortisation expenses increased by $613,357 to $1,351,987 in 2006. Depletion, depreciation and amortisation expenses included depreciation of $176,013 from the Eagle Drill rig.

6.9 Exploration Expenditure Exploration expenditure increased from $4,517,411 in 2005 to $6,066,977 in 2006. This increase in costs reflected the increased activity of the Group and costs incurred in new territories prior to a licence being awarded.

6.10 Gain on Disposal of Discontinued Operations The Group completed the sale of its interests in the Congo generating a one-off gain on sale of $9,200,700 in 2006. All of the disposition agreements were completed in the financial year ended 2006. The gain was calculated after taking into account all relevant costs, including disposal costs and costs in the capitalised cost pool, which totalled $19,962,386.

6.11 Finance Income (Costs) Interest income of $1,336,351 in 2006 was $1,006,061 higher than the previous year, as a result of both average higher cash balances and higher average interest rates in 2006. Cash and cash equivalents are typically held in interest-bearing treasury accounts. Invested cash generating this income was raised by the issue of the $60 million unsecured convertible bonds on 27 March 2006. Other finance costs in 2006 totalled $4,642,126 compared to $491,824 in the previous year. This substantial increase arose from the issue of $60 million unsecured convertible bonds in March 2006. Convertible bonds were separated into liability and derivative liability components (being the bondholders’ conversion option) and each component is recognised separately. The change in the fair value of the convertible bonds conversion options which is primarily due to the increase in share price resulted in a loss of $24,851,295 in 2006. In 2006 the Group recognised an unrealised gain in the fair value of investment in warrants of $195,178. This relates to the Group’s holding of 1,500,000 warrants in the Afren received as partial consideration from sale of Heritage Congo in 2006.

149 6.12 Discontinued Operations The operations of the Kouakouala A licence and Noumbi permit in the Congo have been classified as discontinued operations in 2005 and 2006.

Year ended 31 December 2005 2006 $$ Revenue Petroleum and natural gas ...... 5,444,936 5,116,368 Interest ...... 41,361 — Other ...... 1,013,010 645,915 6,499,307 5,762,283 Operating Expenses Operating ...... 991,956 902,776 Royalties ...... 816,740 767,455 Foreign exchange losses ...... 69,623 — Depletion, depreciation and amortisation ...... 1,110,547 843,562 2,988,866 2,513,793 Discontinued earnings for the year ...... 3,510,441 3,248,490

Production from the Kouakouala field in the Congo declined from 318 bopd in 2005 to 217 bopd in 2006. Revenue from the Kouakouala field decreased from $5,444,936 in 2005 to $5,116,368 due to a 29 per cent. reduction in sales volumes, offset partly by a 32 per cent. increase in the average commodity price from $47.53 in 2005 to $62.53 in 2006. The reduction in revenue resulted in earnings from discontinued operations decreasing from $3,510,441 in 2005 to $3,248,490 in 2006.

6.13 Net Loss for the Year Net loss totalled $28,367,755 in 2006, compared to a net loss of $8,262,225 in 2005. Net basic and diluted loss per HOC Common Share was $(1.29) in 2006, compared to a net basic and diluted loss per HOC Common Share of ($0.38) in 2005.

150 6.14 Capital Expenditures The following table sets out capital expenditures for the years ended 31 December 2005 and 2006:

Year ended Period ended 31 December 12 December 2005 2006 $$ Uganda Drilling ...... 2,466,385 11,999,638 Seismic ...... 1,059,395 — Other ...... 2,123,457 1,665,298 5,649,237 13,664,936

Oman Drilling ...... — 3,209,500 Seismic ...... — 419,942 Other ...... 398,316 698,157 398,316 4,327,599

Russia Seismic ...... — 1,345,524 Acquisition of licence interest in 2005 and other ...... 6,080,697 11,236,331 6,080,697 12,581,855 Other Undeveloped land ...... – 317,786 Drilling equipment ...... 638,613 851,351 Corporate ...... 579,263 1,120,076 1,217,876 2,289,213

Total from continuing operations ...... 13,346,126 32,863,603

Congo (discontinued operations): Drilling ...... 1,683,333 1,785,004 Seismic ...... — 296,898 Other ...... 1,007,595 2,824,852 2,690,928 4,906,754 Total capital expenditures ...... 16,037,054 37,770,357

The Kingfisher-1 well in Uganda was spud in August 2006. This deviated well was drilled to a total depth of 3,195 metres and was completed in March 2007. Development of the Zapadno Chumpasskoye field, which was acquired in November 2005, commenced in 2006 with the acquisition of a 200 km 2D seismic survey, civil works were undertaken, an operating office was established in Nizhnevartovsk and the existing well #226 was re-entered culminating in a preliminary free-flow test that produced 124 bbls of oil over a five hour period. In Oman, the West Bukha-2 appraisal well in Block 8 in Oman was drilled to a total depth of 4,345 metres and tests produced a combined gross flowrate from two zones of approximately 12,750 bopd and 26 MMscf/d of gas. Discontinued operations in 2005 and 2006 relate to the Group’s interests in the Congo which were disposed of in 2006. Cash from discontinued activities of $21,324,969 in 2006 included net proceeds of $27,052,515, offset by a reduction in working capital and disposal of property, plant and equipment.

151 7. RESULTS OF CONTINUING OPERATIONS FOR THE YEARS ENDED 31 DECEMBER 2004 AND 2005 PREPARED IN ACCORDANCE WITH CANADIAN GAAP 7.1 Group Results The following table sets forth the Group’s results for the years ended 31 December 2004 and 2005 prepared in accordance with Canadian GAAP.

2004 2005 $$ Revenue Petroleum and natural gas ...... 5,592,721 6,286,702 Interest ...... 560,926 371,651 Other ...... 443,335 1,355,369 6,596,982 8,013,722 Expenses Operating ...... 1,442,016 1,653,657 Royalties ...... 345,656 816,740 General & administrative ...... 2,633,667 5,249,862 Interest ...... — 491,824 Foreign exchange (gains) losses ...... (1,488,026) 1,240,529 Depletion, depreciation and accretion ...... 633,643 1,636,008 Write-down of unproved petroleum and natural gas interests ...... 934,771 724,915 4,501,727 11,813,535 Earnings (loss) before the under noted ...... 2,095,255 (3,799,813) Gain on sale of property and equipment ...... 26,269,113 — Net earnings (loss) for the year ...... 28,364,368 (3,799,813)

7.2 Petroleum and Natural Gas Production The Group’s net production in bopd from continuing operations is analysed below.

Year ended 31 December Average net annual production 2004 2005 Bpd Bpd Congo ...... 195 318 Oman Condensate ...... 148 69 LPG...... 70 71 218 140 413 458

Net production from the Kouakouala field in the Congo averaged 318 bopd in 2005, 63 per cent. higher than in 2004. The increase arose from an additional producing well (KKL-401) brought into production in the first quarter of 2005. Net production from the Bukha field, Oman declined from 218 bopd in 2004 to 140 bopd in 2005. This reduction was primarily due to the Government of Oman becoming entitled, during 2005, to a share of production after full cost recovery was achieved. Overall, gross field production of liquids declined by 6 per cent. to 2,748 bopd in 2005, which was in line with expectations for this mature asset.

152 7.3 Petroleum and Natural Gas Revenue Petroleum and natural gas revenue may be analysed as follows:

2004 2005 2004 2005 $ $ $/bbl(1) $/bbl(1) Congo ...... 2,304,373 5,444,936 34.58 47.53 Oman Condensate ...... 2,991,096 468,816 40.86 52.24 LPG...... 297,252 372,950 11.30 14.70 3,288,348 841,766 33.05 24.51 5,592,721 6,286,702 33.66 42.22

(1) As a result of the periodic nature of condensate sales from the Bukha field, Oman, $/bbl is based on net sales volumes rather than net production volumes.

Petroleum and natural gas revenue increased by $693,981 (12 per cent.) in 2005 to $6,286,702. $1,273,919 of this increase resulted from a 25 per cent. increase in average commodity prices, offset by $579,938 from a 10 per cent. reduction in sales volumes. The average sales price per barrel increased from $33.66 in 2004 to $42.22 in 2005. Revenue would have been higher in 2005, save for the periodic nature of condensate sales from the Bukha field, Oman. In 2004, 73,207 bbls of condensate were sold, compared to 8,975 in 2005. However, a sale of approximately 17,500 bbls of condensate net to the Group took place in the first quarter of 2006.

7.4 Other Income Other income in 2004 and 2005 included the Group’s share of a pipeline tariff in the Congo. Other income in 2005 also included drilling income of $342,973 from the Group’s 50 per cent. share of Eagle Drill. In 2005, Eagle Drill was the drilling contractor for the operator of Block 2, Uganda, the first well (Mputa-1) spud in December 2005 and the drilling programme continued into 2006.

7.5 Interest Income Interest income of $371,651 in 2005 was $189,275 (34 per cent.) lower than the previous year, as a result of lower average cash balances in 2005 and higher average interest rates in 2004, principally from a $14 million note receivable (denominated in Euros) that bore interest at Euribor plus 2.65 per cent. The note receivable was repaid in three tranches during 2004 and 2005, with the final payment received in March 2005.

7.6 Operating Expenses Operating expenses increased by $211,641 (15 per cent.) in 2005 to $1,653,657. Total operating costs from the Kouakouala and Oman operations in 2005 were similar to the previous year. The increase in 2005 arose from the Group’s 50 per cent. share of Eagle Drill’s operating costs from drilling in Block 2, Uganda.

7.7 General and Administrative General and administrative expenses of $5,249,862 in 2005 were approximately double those incurred in the previous year. During 2005, the Group grew substantially, employing additional staff, appraising and undertaking operations in new territories and establishing a management and finance office in Switzerland. The Group’s level of activity also increased in 2005, notably linked to the acquisition of the Zapadno Chumpasskoye field in Russia and two memoranda of understanding entered into during the year in the KRI. General and administrative expenses in 2005 included $930,000 of one-off costs associated with financing the loan for the London technical services office and the establishment of the management and finance office in Lugano, Switzerland. Additionally, general and administrative expenses in 2005 were higher than the previous year as they included costs of $625,365 from the amortisation of the fair value of stock options granted in 2005 compared to $10,240 in 2004.

153 In 2005, the Group capitalised $1,332,363 (2004—$441,075) of general and administrative costs relating to exploration and development activities.

7.8 Finance Costs Interest on the loan used to re-finance the purchase of the technical services office in London totalled $491,824 in 2005. This loan was obtained in January 2005. There was no interest charge in 2004 as HOC was debt free throughout that year.

7.9 Foreign Exchange Losses There was a foreign exchange loss of $1,240,529 in 2005, primarily as a result of the relative weakening of the Euro against the U.S. dollar. A $14 million note receivable (denominated in Euros) was repaid during the first quarter of 2005 and the funds were retained in Euro-denominated treasury deposits for part of this period.

7.10 Depletion, Depreciation and Accretion Depletion, depreciation and accretion expenses increased by $1,002,365 to $1,636,008 in 2005. This was primarily as a result of a decrease in the level of proved reserves in the Kouakouala field in the Congo as at 31 December 2005, which impacted on the depletion, depreciation and accretion expense in the fourth quarter of the year. The depletion calculation included future costs required to develop reserves in the amount of $625,000 in 2005 compared to $3 million in 2004.

7.11 Impairment of Unproved Petroleum and Natural Gas Interests There was an impairment of unproved interests of $724,915 (Nigeria and Turkmenistan) in 2005 and $934,771 in 2004.

7.12 Gain on Sale of Property and Equipment On 9 June 2004, the Group sold a call option to Maurel et Prom for proceeds of $1.2 million entitling the purchaser to acquire the Group’s overriding royalty interest in the Congo by 30 July 2004 for cash proceeds of $16.4 million, a loan note receivable equivalent to $14 million (denominated in Euros of approximately A11.6 million) due on 31 December 2005 bearing interest at Euribor plus 2.65 per cent. per annum, together with contingent consideration of up to A8.3 million, payable on the sale of all or a portion of its interest in the M’Boundi field or Kouilou permit before 31 December 2005. Concurrent with the exercise of the option, the Group was required to acquire a 7 per cent. working interest in the Noumbi permit in the Congo from the purchaser for a cash consideration of $7 million. On 30 June 2004, Maurel et Prom exercised the option, resulting in a gain on sale of $26,269,113 (Cdn$35,339,838). The net cash consideration of $9.4 million was received in July 2004. The gain on the sale of the Kouilou overriding royalty was calculated after taking into account all relevant costs. The sale of the overriding royalty would have changed the rate of depletion and depreciation for the Congo by more than 20 per cent. Accordingly, the capitalised cost pools and project values of the other projects from this country were taken into account when calculating the gain on sale of $26,269,113.

7.13 Net Earnings (Loss) for the Year There was a net loss of $3,799,813 in 2005, compared to net earnings of $28,364,368 in 2004. Net earnings in 2004 were $2,095,255 before taking into account the one-off gain on the sale of property of $26,269,113. If foreign exchange gains and losses and write-downs of petroleum and natural gas interests were excluded, the loss in 2005 would have been $1,834,369, compared to earnings of $1,542,000 in the previous year. Net losses per HOC Common Share were $0.18 in 2005, compared to earnings per HOC Common Share of $1.33 (basic) and $1.31 (diluted) in 2004.

154 7.14 Capital Expenditures Additions to plant, property and equipment were $20,554,465 in 2005, compared to $37,318,136 in 2004. Capital expenditures in 2005 and 2004 may be analysed by country and category as follows:

Year ended 31 December 2004 2005 $$ Uganda Drilling ...... 6,653,966 2,466,385 Seismic ...... 4,130,388 1,059,395 Other ...... 1,647,725 2,123,457 12,432,079 5,649,237

Congo Drilling ...... 1,030,931 1,683,333 Other ...... 498,793 1,007,595 Acquisition of licence interest ...... 7,000,000 — 8,529,724 2,690,928

Oman Other ...... 172,788 398,316 172,788 398,316

Russia Acquisition of licence interest and other ...... 871,950 6,558,966 871,950 6,558,966

Other Undeveloped lands ...... 2,218,319 3,952,033 Eagle Drill Rig refurbishment ...... 640,812 638,613 Corporate ...... 12,452,464 666,372 15,311,595 5,257,018 Total capital expenditures ...... 37,318,136 20,554,465

8. FIXED PRICE CONTRACTS AND DERIVATIVE FINANCIAL INSTRUMENTS The Group periodically adopts a hedging policy to mitigate certain exposure to commodity pricing risk. No derivative instruments were entered into in the financial years ended 31 December 2004, 2005, 2006 or the nine-month period ended 30 September 2007.

9. CONTRACTUAL OBLIGATIONS AND COMMITMENTS The tables below set out the Group’s net share of outstanding commitments for the respective periods. Work programme obligations comprise the estimated costs of minimum work programmes set out in certain of the Group’s licences in Russia, Uganda and Oman. The Group did not enter into any off-balance sheet arrangements in the financial years ended 31 December 2004, 2005, 2006 or the nine-month period ended 30 September 2007, that would adversely impact on the Group’s financial position or results of operations. At 30 September 2007, in Canada, Russia and Uganda the Group has available tax deductions of $25,418,994 and tax losses of $70,286,702 of which $23,452,398 expires from 2008 to 2027, and the remaining $46,834,304 does not have an expiry period.

155 The Group’s net share of outstanding commitments at 30 September 2007 were estimated at:

Less than After Payments Due by Period Total 1 year 1 - 3 years 4 - 5 years 5 years $ Thousands $ Thousands $ Thousands $ Thousands $ Thousands Long-term debt ...... 17,662 617 1,234 8,334 7,477 Convertible bonds ...... 158,000 — — 158,000 — Operating leases ...... 9,642 229 458 458 8,497 Other long term obligations ...... 140,000 40,000 100,000 — — Work programme obligations ...... 124,759 58,236 52,259 14,065 200 Total contractual obligations ...... 450,063 99,082 153,951 180,857 16,174

The Group’s net share of outstanding commitments at 31 December 2006 were estimated at:

Less than After Payments Due by Period Total 1 year 1 - 3 years 4 - 5 years 5 years $ Thousands $ Thousands $ Thousands $ Thousands $ Thousands Long-term debt ...... 8,212 147 294 294 7,477 Convertible bonds ...... 60,000 — — 60,000 — Operating leases ...... 9,642 229 458 458 8,497 Work programme obligations ...... 16,750 10,000 4,875 1,875 — Total contractual obligations ...... 94,604 10,376 5,627 62,627 15,974

The Group’s net share of outstanding commitments at 31 December 2005 were estimated at:

Less than After Payments Due by Period Total 1 year 1-3 years 4-5 years 5 years $ Thousands $ Thousands $ Thousands $ Thousands $ Thousands Long-term debt ...... 7,768 248 246 246 7,028 Capital lease obligations ...... — — — — — Operating leases ...... 2,659 217 434 434 1,574 Purchase obligations ...... — — — — — Other long-term obligations ...... 875 588 287 — Work programme obligations ...... 19,350 16,950 2,400 — Total contractual obligations ...... 30,652 18,003 3,367 680 8,602

The Group’s net share of outstanding commitments at 31 December 2004 were estimated at:

Less than After Payments Due by Period Total 1 year 1-3 years 4-5 years 5 years $ Million $ Million $ Million $ Million $ Million Work programme obligations ...... 7232—

At 31 December 2004, (save for exploration work commitments included in certain of its exploration permits) the Group did not have any material contractual obligations, lease obligations or commercial commitments outstanding.

156 10. LIQUIDITY AND CAPITAL RESOURCES The Group’s financial strategy has been to fund its capital expenditure programme and any potential acquisitions by selling non-core assets, reinvesting funds from operations, using existing treasury resources, finding new credit facilities and, when considered appropriate, either issuing unsecured convertible bonds or additional HOC Common Shares.

10.1 Capital Resources Nine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRS As at 30 September 2007, the Group had a working capital surplus of $52,828,354 (30 September 2006— $38,325,134), including cash and cash equivalents of $61,894,711. On 16 February 2007, the Group raised $165 million by completing the private placement of convertible bonds described below. Proceeds were used to finance the redemption of outstanding 10 per cent. convertible bonds on 28 March 2007, for $82.5 million plus interest and the remainder was added to working capital to be used for general corporate funding purposes. In October 2007, the Group received a loan of US$9.45 million to refinance the acquisition of a corporate jet. Interest on the loan is variable at a rate of LIBOR plus 1.6 per cent. The loan, which is secured on the corporate jet, is scheduled to be repaid by 19 consecutive quarterly instalments of principal. Each instalment equals to $117,500 with the final instalment being $7,217,500. HOC provided a corporate guarantee to the lender in respect of this loan. On 14 November 2007, HOC completed an equity offering, whereby 3,000,000 HOC Common Shares were issued from treasury at a price of Cdn$60.50 per Common Share for gross proceeds of Cdn$181.5 million.

Year Ended 31 December 2006 Prepared in Accordance with IFRS As at 31 December 2006, the Group had a working capital surplus of $44,467,745.

Year Ended 31 December 2005 Prepared in Accordance with IFRS As at 31 December 2005, the Group had a working capital surplus of $5,686,214.

Year Ended 31 December 2004 Prepared in Accordance with Canadian GAAP As at 31 December 2004, the Group had a working capital surplus of $19,125,890.

10.2 Debt Nine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRS On 17 January 2007, the Group 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 2007. 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 per share subsequent to 31 December 2006. As a result of this conversion, a total amount of $7,104,327 was transferred to Share Capital from convertible bonds and derivative liability component of convertible bonds. On 16 February 2007, HOC raised $165 million gross by completing the 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 may 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. Bondholders have a put option requiring HOC to redeem the bonds at par, plus accrued interest, in the event of a change of control of HOC or revocation or surrender of the Zapadno Chumpasskoye licence in Russia. In the event of a change of control and redemption of the bond or exercise of the conversion rights a cash payment of up to $19,700 on each bond will be made to the bondholder, the amount of which depends upon the date of redemption and market value at the date of any change of control event. Under the conditions of the HOC Bonds, HOC is required to take (or to procure that there is taken) all necessary action to ensure that immediately upon completion of the Plan of Arrangement, at its option, either (a) the Company is substituted under the bonds as principal debtor in place of HOC or becomes a guarantor under the bonds and, in either case, to

157 make necessary consequential amendments such that the bonds may be converted into or exchanged for Ordinary Shares; or (b) such amendments are made to the bonds such that the bonds may be converted into or exchanged for Ordinary Shares. The bonds included conversion features which in certain circumstances could be settled in cash and so these features represent a derivative financial instrument which is classified as a liability. The fair value of the liability component of the bonds net of issue costs was estimated at $140,154,215. The fair value of derivative liability representing the bondholders conversion feature was estimated at $17,866,517 on 16 February 2007. The difference between the $165.0 million due on maturity and the initial liability component is accreted using the effective rate method and recorded as finance costs in the income statement. In July 2007, a bondholder with U.S.$7 million of bonds gave notice of exercise of 70 bonds and received 148,937 HOC Common Shares in August 2007. As a result of this conversion, a total amount of $8,944,487 was transferred to share capital from convertible bonds, derivative liability component of convertible bonds and accrued liabilities. In October 2007, the Group received a loan of $9.45 million to refinance the corporate jet acquisition. Interest on the loan is variable at a rate of LIBOR plus 1.6%. The loan, which is secured on the corporate jet, is scheduled to be repaid by 20 consecutive quarterly instalments of principal. Each instalment equals to $117,500 with the final instalment being $7,217,500. HOC provided a corporate guarantee to the lender.

Year Ended 31 December 2006 Prepared in Accordance with IFRS 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 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 2007. 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 U.S.$18 per share subsequent to 31 December 2006. As a result of this conversion, a total amount of $7,104,327 was transferred to share capital from convertible bonds liability and derivative liability component of convertible bonds.

Year Ended 31 December 2005 Prepared in Accordance with IFRS In January 2005, HOC received a sterling denominated loan of £4.5 million to refinance the acquisition of its technical services office at 34 Park Street, Mayfair, London W1K 2JD. Interest on the loan is fixed at 6.515 per cent. for the first five years and then is variable at a rate of LIBOR plus 1.35 per cent. The loan, which is secured on the property, is scheduled to be repaid by 240 instalments of capital and interest at monthly intervals, subject to a residual debt at the end of the term of the loan of $3.5 million (£1.86 million).

Year Ended 31 December 2004 Prepared in Accordance with Canadian GAAP The Group had no debt during 2004.

10.3 Share Capital Nine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRS During the nine-month period ended 30 September 2007, HOC issued 426,715 HOC Common Shares on conversion of convertible bonds and 32,000 HOC Common Shares on exercise of stock options (60,000 during the nine-month period ended 30 September 2006).

Year Ended 31 December 2006 Prepared in Accordance with IFRS During 2006, HOC issued 143,333 HOC Common Shares on the exercise of options.

158 Year Ended 31 December 2005 Prepared in Accordance with IFRS In 2005, HOC issued 546,667 HOC Common Shares on the exercise of options. Pursuant to a Normal Course Issuer Bid in place between 4 November 2005 and 3 November 2006, HOC purchased an aggregate of 135,100 HOC Common Shares under the Normal Course Issue Bid at an average price of $7.85 per share, which were cancelled.

Year Ended 31 December 2004 Prepared in Accordance with Canadian GAAP During 2004, the HOC issued 462,334 HOC Common Shares: 442,334 by the exercise of options and 20,000 by the exercise of warrants. A Normal Course Issuer Bid programme commenced on 4 November 2003, expired on 3 November 2004, and was replaced by a further Normal Course Issuer Bid programme that commenced on 4 November 2004 and expired on 3 November 2005. In 2004, HOC did not acquire any HOC Common Shares. From time to time, HOC believes that the buy-back of HOC Common Shares represents an appropriate use of funds when it is the opinion of management that the market price of HOC Common Shares is at a discount to the fair value of the shares. During 2004, HOC’s trading symbol was changed from HOC.A to HOC. At HOC’s Annual and Special General Meeting on 23 June 2004, shareholders approved the removal of Class ‘‘B’’ HOC Common Shares and agreed to redesignate Class ‘‘A’’ shares as HOC Common Shares.

10.4 Cash Flows

Nine-Month Periods Ended 30 September 2006 and 2007 Prepared in Accordance with IFRS The following table sets forth the Group’s cash flows for the nine-month periods ended 30 September 2006 and 2007:

Nine-month periods ended 30 September 2006 2007 $$ (Unaudited) Net cash flows used in operating activities ...... (8,331,393) (7,212,661) Net cash used in investing activities ...... (12,074,902) (53,535,576) Net cash from financing activities ...... 57,356,469 75,080,072 Cash provided by discontinued operations ...... 1,009,595 — Foreign exchange gains on cash held in foreign currency ...... 308,481 701,730 Net increase in cash and cash equivalents ...... 38,268,250 15,033,565 Cash and cash equivalents at the end of the period ...... 46,851,571 61,894,711

The net cash outflow from operating activities in the nine-month period ended 30 September 2007 was $7,212,661, compared to $8,331,393 in the same period in the previous year. This increase was primarily due to an increased loss from continuing operations. Net cash used in investing activities increased from $12,074,902 in the nine-month period ended 30 September 2006 to $53,535,576 in the nine-month period ended 30 September 2007. Investing activities principally comprises property, plant and equipment capital expenditures. Net cash from financing activities increased to $75,080,072 in the nine-month period ended 30 September 2007 primarily as a result of the issue of $165 million unsecured convertible bonds in February 2007, offset by the redemption of the outstanding $55 million of the convertible bonds issued in 2006 at a premium of 150 per cent. A total of $5 million of the $60 million convertible bonds issued in 2006 were converted into equity prior to the issue of the redemption notice.

159 Years Ended 31 December 2005 and 2006 Prepared in Accordance with IFRS The following table sets forth the Group’s cash flows for the years ended 31 December 2005 and 2006:

Year ended 31 December 2005 2006 $$ Net cash flows used in operating activities ...... (7,854,323) (12,737,451) Net cash used in investing activities ...... (11,946,720) (28,823,833) Net cash from financing activities ...... 9,020,147 58,031,186 Discontinued operations ...... 4,313,817 21,324,969 Foreign exchange gains (losses) on cash held in foreign currency ...... (1,185,123) 482,954 Net increase (decrease) in cash and cash equivalents ...... (7,652,202) 38,277,825 Cash and cash equivalents at the end of the year ...... 8,583,321 46,861,146

Net cash outflows from continued operating activities increased from $7,854,323 in 2005 to $12,737,451 in 2006 as a result of the increased loss from continuing operations. Net cash from financing activities increased from $9,020,147 in 2005 to $58,031,186 in 2006 and primarily consisted of the net proceeds of $57 million from the unsecured convertible bond issued in March 2006. Net cash used in investing activities increased from $11,946,720 in 2005 to $28,823,833 in 2006. Investing activities principally comprises property, plant and equipment capital expenditures.

Years Ended 31 December 2004 and 2005 Prepared in Accordance with Canadian GAAP

Year ended 31 December 2004 2005 $$ Net earnings (loss) from continuing operations ...... 28,364,368 (3,799,813) Items not involving cash ...... (26,498,359) 4,496,936 Net cash flows from operating activities ...... 1,866,009 697,123 Net cash from financing activities ...... 604,953 9,020,147 Net cash used in investing activities ...... (11,310,312) (16,184,349) Foreign exchange gains (losses) on cash held in foreign currency ...... 906,001 (1,185,123) Net increase (decrease) in cash and cash equivalents ...... (7,933,349) (7,652,202) Cash and cash equivalents at the end of the year ...... 16,235,523 8,583,321

11. CRITICAL ACCOUNTING POLICIES 11.1 Critical IFRS accounting policies (a) Exploration and evaluation expenditure The Group applies a modified full cost method of accounting for E&E costs, having regard to the requirements of IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’. Under this method of accounting, costs of exploring for and evaluating petroleum and natural gas properties are capitalised on a licence or prospect basis and the resulting assets are tested for impairment by reference to appropriate cost pools. Such cost pools are based on geographic areas and are not larger than a segment. The Group had six cost pools: Uganda, Russia, Oman, DRC, Pakistan and the Congo during the periods under review. E&E costs related to each licence or project are initially capitalised within ‘Intangible exploration assets’. Such E&E costs may include costs of licence acquisition, technical services and studies, seismic acquisition, exploration drilling and testing and the projected costs of retiring the assets (if any), but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the income statement as they are incurred. Tangible assets acquired for use in E&E activities are classified as property, plant and equipment. However, to the extent that such a tangible asset is consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded as part of the cost of the intangible asset.

160 Intangible E&E assets related to each exploration licence/prospect are not depreciated, but carried forward until the existence (or otherwise) of commercial reserves has been determined. The Group’s definition of commercial reserves for such purpose is proved and probable reserves on an entitlement basis. Proved and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty (see below) to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent. statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50 per cent. statistical probability that it will be less. The equivalent statistical probabilities for the proved component of proved and probable reserves are 90 per cent. and 10 per cent., respectively. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: – a reasonable assessment of the future economics of such production; – a reasonable expectation that there is a market for all or substantially all the expected hydrocarbon production; and – evidence that the necessary production, transmission and transportation facilities are available or can be made available.

Furthermore: (i) Reserves may only be considered proved and probable if producibility is supported by either actual production or conclusive formation test. The area of reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proved and probable classification when successful testing by a pilot project, the operation of an installed programme in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or programme was based.

If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a cost pool basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production assets within property, plant and equipment. E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist. Where the E&E assets concerned fall within the scope of an established full cost pool, the E&E assets are tested for impairment together with all development and production assets associated with that cost pool, as a single cash generating unit. The aggregate carrying value is compared against the expected recoverable amount of the pool, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. Where the E&E assets to be tested fall outside the scope of any established cost pool, there will generally be no commercial reserves and the E&E assets concerned will generally be written off in full.

(b) Property, plant and equipment

(i) Development and production assets The Group had three cost pools at the development and production stage: Congo, Russia and Oman during the period under review.

161 Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above and the projected cost of retiring the assets. The net book values of producing assets are depleted on a field-by-field basis using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves of the field, taking into account estimated future development expenditures necessary to bring those reserves into production. An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash generating unit where the cash flows generated by the fields are interdependent. (ii) Other assets Other property, plant and equipment are stated at cost less accumulated depreciation and any impairment in value. The assets’ useful lives and residual values are assessed on an annual basis. Furniture and fittings are depreciated using reducing balance method at 20% per year. Land is not subject to depreciation. Drilling rig equipment is depreciated using the unit-of-production method based on 2,740 drilling days with a 20 per cent. residual value. The corporate jet is depreciated over its expected useful life of 69 months. Depreciation is charged so as to write off the costs, less estimated residual value of the corporate jet on a straight-line basis. Corporate capital assets are depreciated on a straight-line basis over their estimated useful lives. The building is depreciated on a straight-line basis over 40 years.

(c) Provisions Asset retirement obligations Provision is made for the estimated cost of any asset retirement obligations when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount has been reliably estimated. Provisions are not recognised for future operating losses. Asset retirement obligation expense is capitalised in the relevant asset category unless it arises from the normal course of production activities. Provisions are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the balance sheet date. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognised as finance costs whereas increases due to changes in estimated future cash flows are capitalised.

162 11.2 The year ended 31 December 2004 and conversion from Canadian GAAP to IFRS The Consolidated Balance Sheet as at 1 January 2005 and Consolidated Balance Sheet and Consolidated Income Statement for the year ended 31 December 2005 and conversion from Canadian GAAP to IFRS The following tables are based on information extracted from the audited financial statements at 31 December 2004 and for the year ended 31 December 2005 and reconcile the Consolidated Balance Sheet and Consolidated Income Statement reported under Canadian GAAP and as restated under IFRS: (a) At the date of transition to IFRS at 1 January 2005:

Effect of Previous transition to Notes Canadian GAAP IFRS IFRS $$$ Assets Non-current assets: Intangible exploration assets ...... (b),(c) — 32,725,642 32,725,642 Intangible development costs ...... 1,013,012 — 1,013,012 Property, plant and equipment ...... (a),(b),(d),(g) 54,083,097 (32,306,191) 21,776,906 55,096,109 419,451 55,515,560

Current assets Inventories ...... (d) 94,483 24,976 119,459 Prepaid expenses ...... 272,168 — 272,168 Trade and other receivables ...... 8,920,963 — 8,920,963 Cash and cash equivalents ...... 16,235,523 — 16,235,523 25,523,137 24,976 25,548,113 Total Assets ...... 80,619,246 444,427 81,063,673

Liabilities Current liabilities Trade and other payables ...... 6,397,247 — 6,397,247 6,397,247 — 6,397,247 Non-current liabilities Provisions ...... 328,553 — 328,553 Total Liabilities ...... 6,725,800 — 6,725,800 Net Assets ...... 73,893,446 444,427 74,337,873

Equity Share capital ...... 21,434,168 — 21,434,168 Reserves ...... 24,421 — 24,421 Retained earnings ...... (a),(c),(d),(g) 52,434,857 444,427 52,879,284 Total Equity ...... 73,893,446 444,427 74,337,873

163 (b) At 31 December 2005: Effect of Previous transition to Notes Canadian GAAP IFRS IFRS $$$ Assets Non-current assets: Intangible exploration assets ...... (b),(c),(f) — 43,503,704 43,503,704 Intangible development costs ...... 1,187,371 — 1,187,371 Property, plant and equipment ...... (a),(b),(d),(g) 74,729,540 (49,446,988) 25,282,552 75,916,911 (5,943,284) 69,973,627

Current assets Inventories ...... (d) 216,474 35,441 251,915 Prepaid expenses ...... 219,222 — 219,222 Trade and other receivables ...... 1,318,450 — 1,318,450 Cash and cash equivalents ...... 8,583,321 — 8,583,321 10,337,467 35,441 10,372,908 Total Assets ...... 86,254,378 (5,907,843) 80,346,535

Liabilities Current liabilities Trade and other payables ...... 4,438,649 — 4,438,649 Borrowings ...... 248,045 — 248,045 4,686,694 — 4,686,694

Non-current liabilities Borrowings ...... 7,520,438 — 7,520,438 Deferred tax liabilities ...... (f) 2,346,605 (2,346,605) — Provisions ...... 434,849 — 434,849 10,301,892 (2,346,605) 7,955,287 Total Liabilities ...... 14,988,586 (2,346,605) 12,641,981 (71,265,792) (3,561,238) 67,704,554

Equity Share capital ...... 22,854,418 — 22,854,418 Reserves ...... (e) 517,209 456,747 973,956 Retained earnings (deficit) ...... (a),(c),(d),(e),(g) 47,894,165 (4,017,985) 43,876,180 Total Equity ...... 71,265,792 (3,561,238) 67,704,554

164 (c) Reconciliation of loss for the year ended 31 December 2005: Effect of Previous transition to Notes Canadian GAAP IFRS IFRS $$$ Revenue Petroleum and natural gas ...... 841,766 — 841,766 Drilling services ...... 342,359 — 342,359 1,184,125 — 1,184,125

Expenses Petroleum and natural gas ...... 465,110 — 465,110 Drilling rig operating ...... 196,804 — 196,804 General and administrative ...... (e) 5,249,649 456,747 5,706,396 Foreign exchange losses ...... 1,170,906 — 1,170,906 Depletion, depreciation and amortisation ..... (c),(d),(g) 536,093 202,537 738,630 Exploration expenditure ...... (a) — 4,517,411 4,517,411 Impairment of unproved oil & gas interest .... (a) 724,915 (724,915) — 8,343,477 4,451,780 12,795,257

Interest income (costs) Interest income ...... 330,290 — 330,290 Finance costs ...... (491,824) — (491,824) (161,534) — (161,534) Loss from continuing operations ...... (7,320,886) (4,451,780) (11,772,666) Earnings from discontinued operations ...... (g) 3,521,073 (10,632) 3,510,441 Net loss ...... (3,799,813) (4,462,412) (8,262,225)

(a) Pre-licence costs Under Canadian GAAP, certain costs incurred prior to having obtained licence rights were included within property, plant and equipment. Under IFRS, such expenditures are expensed as incurred. The impact on adoption of IFRS at 1 January 2005 is a reduction in property, plant and equipment and retained earnings of $2,162,301. As at 31 December 2005, this has resulted in a reduction in property, plant and equipment and retained earnings of $5,954,798, an increase in exploration expenditure for the year of $4,517,411, and a decrease in the impairment of unproved petroleum and natural gas interests recognised in the year of $724,915. The income tax impact was in a further reduction of property, plant and equipment of $2,346,605 and a corresponding decrease in the deferred tax liability. (b) Reclassification of exploration and evaluation costs Under Canadian GAAP property, plant and equipment included certain exploration and evaluation expenditure incurred within established geographic cost pools. Under IFRS, such exploration and evaluation costs are recognised as tangible or intangible based on their nature. At 31 December 2005, this has resulted in the reclassification from property, plant and equipment to intangible exploration of $45,111,919 (1 January 2005: $32,589,744). (c) Capitalisation of tangible asset depreciation to intangible assets Under IFRS, intangible exploration and evaluation costs include the depreciation of any tangible assets utilised in incurring the costs. As these assets were classified as property, plant and equipment under Canadian GAAP, depreciation of fixed assets was not included in the balance. The impact on adoption of IFRS at 1 January 2005 is an increase in intangible exploration and retained earnings of $135,898. At 31 December 2005, an increase in intangible exploration and retained earnings of $171,728, and a decrease in depreciation expense for the year of $35,830.

165 (d) Reversal of impairment Under IFRS, impairment losses previously recorded are reversed if the conditions giving rise to the impairment have reversed. The reversal of impairment losses was not permitted under Canadian GAAP. The impact on adoption of IFRS at 1 January 2005 is an increase in inventory of $24,976, an increase in property, plant and equipment of $1,656,846, and an increase in retained earnings of $1,681,822. At 31 December 2005, this has resulted in increases in inventory of $35,441, property, plant and equipment of $1,442,748, retained earnings of $1,478,189, and depletion expense for the year of $203,633. (e) Share-based payments Under Canadian GAAP, the Group recognised an expense related to their share-based payments on a straight-line basis through the date of full vesting. Under IFRS, the Group is required to recognise the expense over the individual vesting periods for the graded vesting awards. At 31 December 2005, this has resulted in increases in general and administrative expenses and share- based payments reserves of $456,747, with a corresponding decrease in retained earnings. (f) Deferred tax Under Canadian GAAP, the Corporation recognised a deferred tax liability and corresponding increase in property, plant and equipment associated with its acquisition of Russian properties. However, under IFRS deferred tax is only recognised on the initial recognition of an asset if it is acquired through a business combination. At 31 December 2005 and 31 December 2006, this has resulted in a reduction in property, plant and equipment and deferred tax liability of $2,346,605. There was no impact at 1 January 2005. (g) Depletion policy Upon transition to IFRS, the Corporation adopted a policy of depleting petroleum and natural gas interests on a units of production basis over proved plus probable reserves. The depletion policy under Canadian GAAP was units of production over proved reserves. The impact on adoption to IFRS at 1 January 2005 is an increase in property, plant and equipment and retained earnings of $789,008. At 31 December 2005, this resulted in increases in property plant and equipment and retained earnings of $743,642, and depletion expense for the year of $34,734, and a decrease in earnings from discontinued operations of $10,632. At 31 December 2006, this resulted in decreases in property plant and equipment of $233,631, retained earnings of $211,900, and earnings from discontinued operations of $674,905, and increases in inventory of $21,731, and depletion expense for the year of $280,637.

12. RELATED PARTY TRANSACTIONS Nine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRS During the nine-month period ended 30 September 2007, general and administrative expenses included advisory fees of $806,607 ($644,258 in the nine-month period ended 30 September 2006) charged by Mr. Anthony Buckingham, a director of HOC and CEO. Mr. Paul Atherton, a director of HOC, is also a director and CFO of SeaDragon. The Group acquired 605,000 common shares in SeaDragon on 9 March 2007 through the sale of its 65 per cent. interest in Pipelay and Naturalay Technologies.

Year Ended 31 December 2006 Prepared in Accordance with IFRS In 2006, general and administrative expenses included an advisory fee of $1,494,317 charged by Mr. Anthony Buckingham, a director of HOC, who was appointed CEO on 6 October 2006.

Year Ended 31 December 2005 Prepared in Accordance with IFRS In 2005, the Group established a management and finance office in Switzerland that required Mr. Anthony Buckingham, a director of HOC, to relocate and he received a relocation allowance of $275,918. In 2005, general and administrative expenses included an advisory fee of $877,686 charged by this director.

166 Year Ended 31 December 2004 Prepared in Accordance with Canadian GAAP In 2004, general and administrative expenses included an advisory fee of $429,208 charged by Mr. Anthony Buckingham.

13. CURRENT TRADING AND PROSPECTS The Company is well positioned to benefit from a series of exploration, appraisal and development drilling in 2008. Drilling programmes in Blocks 3A and 1 are scheduled to commence in Uganda in 2008. An exploration well is also scheduled to commence drilling in the Miran licence in the KRI in the second half of 2008. Production from the Zapadno Chumpasskoye field 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 2008.

167 PART VI—CAPITALISATION AND INDEBTEDNESS

The following tables show the consolidated capitalisation of the Group and the indebtedness of the Group as at 31 December 2007.

As at Capitalisation 31 December 2007 (Thousands of $) Shareholders’ equity Share capital ...... 217,447 Reserves ...... 42,867 Capital and reserves ...... 260,314 Total Capitalisation ...... 260,314

As at 31 December 2007 (Thousands of $) Total current debt Current portion of secured long-term debt ...... 628 628 Total non-current debt (excluding current portion of long-term debt) Non-current portion of secured long-term debt ...... 17,036 Convertible bonds ...... 137,213 Derivative financial liability ...... 36,740 190,989 Total indebtedness ...... 191,617

The following table shows the net financial indebtedness of the Group as at 31 December 2007.

As at 31 December 2007 (Thousands of $) Cash ...... 230,121 Cash equivalents ...... — Liquidity ...... 230,121 Current financial indebtedness Current portion of long-term debt ...... (628) (628) Non-current financial indebtedness Non-current portion of long-term debt ...... (17,036) Convertible bonds ...... (137,213) Derivative financial liability ...... (36,740) (190,989) Net funds ...... 38,504

As at 31 December 2007, the Group had no material indirect and contingent indebtedness. Capitalisation and indebtedness does not include retained deficit.

168 PART VII—FINANCIAL INFORMATION A. FINANCIAL INFORMATION RELATING TO THE COMPANY

Set out on the following pages is financial information relating to the Company as at 28 March 2008 prepared in accordance with International Financial Reporting Standards (IFRS).

169 Accountant’s report on historical financial information of Heritage Oil Limited

KPMG LLP 8 Salisbury Square, London, EC4Y 8BB, United Kingdom

The Directors Heritage Oil Limited Ordnance House 31 Pier Road St. Helier Jersey, JE4 8PW Channel Islands Dear Sirs

Heritage Oil Limited (the ‘‘Company’’) We report on the financial information set out on pages 172 to 173 in relation to the Company. This financial information has been prepared for inclusion in the prospectus that will be dated 28 March 2008 of the Company on the basis of the accounting policies set out in note 1. This report is required by paragraph 20.1 of Annex I of the Prospectus Directive Regulation and is given for the purpose of complying with that paragraph and for no other purpose.

Responsibilities The Directors of the Company are responsible for preparing the financial information on the basis of preparation set out in note 1 to the financial information and in accordance with International Financial Reporting Standards (IFRS). It is our responsibility to form an opinion on the financial information and to report our opinion to you. Save for any responsibility arising under Prospectus Rule 5.5.3R (2)(f) to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to its inclusion in the prospectus.

Basis of opinion We conducted our work in accordance with Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. Our work included an assessment of evidence relevant to the amounts and disclosures in the financial information. It also included an assessment of the significant estimates and judgments made by those responsible for the preparation of the financial information and whether the accounting policies are appropriate to the entity’s circumstances, consistently applied and adequately disclosed. We planned and performed our work so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the financial information is free from material misstatement whether caused by fraud or other irregularity or error.

Opinion In our opinion, the financial information gives, for the purposes of the prospectus that will be dated 28 March 2008, a true and fair view of the state of affairs of the Company as at the date stated and of its changes in Shareholder’s equity for the period then ended in accordance with the basis of preparation set out in note 1 and in accordance with IFRS as described in note 1.

170 Declaration For the purposes of Prospectus Rule 5.5.3R (2)(f) we are responsible for this report as part of the prospectus and declare that we have taken all reasonable care to ensure that the information contained in this report is, to the best of our knowledge, in accordance with the facts and contains no omission likely to affect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 of Annex I of the Prospectus Directive Regulation. Yours faithfully

(Signed) ‘‘KPMG LLP’’ KPMG LLP 28 March 2008

171 HERITAGE OIL LIMITED BALANCE SHEET As at 6 February 2008

$ ASSETS Current assets: Cash and cash equivalents ...... 42 42 SHAREHOLDER’S EQUITY Share capital (note 2) ...... 42 42

See accompanying notes to balance sheet.

STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

$ At beginning of the period ...... — Profit for the period ...... — Other recognised income and expense ...... — Issue of share capital ...... 42 At end of the period ...... 42

The Company has not traded since incorporation on 6 February 2008.

172 HERITAGE OIL LIMITED NOTES TO BALANCE SHEET As at 6 February 2008

Heritage Oil Limited (the ‘‘Company’’) was incorporated under the Companies (Jersey) Law 1991 on 6 February, 2008. The balance sheet is prepared in accordance with International Financial Reporting Standards (IFRS). 1. Significant accounting policies: (a) Basis of presentation: The majority of the Company’s business will be transacted in U.S. dollars and, accordingly, the Company’s functional and reporting currency is U.S. dollars. (b) Cash and cash equivalents: The Company considers deposits in banks, certificates of deposit and short-term investments with original maturities of three months or less as cash and cash equivalents. 2. Share capital: (a) Authorized: Unlimited number of Ordinary Shares without par value. (b) Issued: At Incorporation there was one Ordinary Share issued at $42 (£21.29). 3. Subsequent events: On 22 February 2008, a second Ordinary Share was issued at $41 (£21.19). On 22 February 2008 the Company entered into an agreement with, inter alia, Heritage Oil Corporation (‘‘HOC’’) (the ‘‘Arrangement Agreement’’). Under the Arrangement Agreement, each holder of HOC Common Shares will exchange their shares for Ordinary Shares or Exchangeable Shares of HOC on a one-for-ten basis. Exchangeable Shares of HOC have certain special rights including the right to direct a trustee as to how it should exercise a number (equal to the number of Exchangeable Shares held) of the votes attaching to the Special Voting Share to be issued by the Company for these purposes. On 28 March 2008 the Company entered into the following agreements: • the Voting and Exchange Trust Agreement under which the Company will issue one Special Voting Share. The Special Voting Share will have the number of votes, which may be cast at any meeting at which holders of Ordinary Shares are entitled to vote, equal to the number of Exchangeable Shares of HOC outstanding at the relevant time. Each holder of Exchangeable Shares of HOC on the record date for any meeting at which holders of Ordinary Shares are entitled to vote will be entitled to instruct the Trustee to exercise those votes attached to the Special Voting Share for each Exchangeable Share of HOC held or to obtain a proxy from the Trustee entitling the holder to vote directly, at the relevant meeting, the votes attached to the Special Voting Share to which the holder is entitled. • the Support Agreement under which for so long as any Exchangeable Shares of HOC remain outstanding, the Company has made certain covenants, to the fullest extent permitted by law, in favour of HOC including, but not limited to, the following: (a) the Company will not declare or pay dividends on Ordinary Shares unless HOC is able to declare and pay and simultaneously declares and pays, as the case may be, an equivalent dividend on the Exchangeable Shares; (b) the Company will advise HOC in advance of the declaration of any dividend by the Company; and (c) the Company will take all actions and do all things reasonably necessary to enable and permit HOC and Alberta CallCo to perform their obligations, if any, arising upon the liquidation, dissolution or winding up of HOC, the receipt of a Retraction Request, the exercise by Alberta CallCo of its right to purchase Exchangeable Shares that are the subject of a Retraction Request and the exercise and the exercise by Alberta CallCo of its right to purchase all Exchangeable Shares in the event of the a proposed liquidation, dissolution or winding up of HOC. The Company has agreed to take all such actions as are reasonably necessary to cause all Ordinary Shares deliverable in connection with Exchangeable Shares to be listed and posted for trading on all stock exchanges on which outstanding Ordinary Shares are listed. The Company has also agreed not to exercise any voting rights attached to the Exchangeable Shares owned by it or any of its affiliates on any matter considered at meetings of holders of Exchangeable Shares. • the Relationship Agreement with Anthony Buckingham and Albion Energy Limited governing the relationship between the parties. • the Sponsor’s Agreement under which, inter alia: the Company appointed JPMorgan Cazenove Limited as sponsor in connection with the application for admission of its Ordinary Shares to the Official List and to trading on the London Stock Exchange (the ‘‘LSE’’); the Company has agreed to pay the Sponsor a management fee of £1,000,000 plus VAT on Admission; the Company has agreed to pay (together with any related value added tax) certain costs, charges, fees and expenses, in connection with, or incidental to Admission; the Company has given certain warranties and undertakings to the Sponsor and given certain indemnities to the Sponsor that are typical of an arrangement of this nature.

173 B. AUDITED (AND UNAUDITED) FINANCIAL INFORMATION RELATING TO HOC

Set out on the following pages is unaudited consolidated financial information of HOC for the nine month period ended and as at 30 September 2006, as prepared by management, in accordance with IFRS and audited consolidated financial information of HOC for and as at the three years and nine-month period ended 30 September 2007 (comprising the audited financial statements for the years ended 31 December 2004 and 31 December 2005 prepared in accordance with Canadian GAAP, and audited financial information for the years ended and as at 31 December 2005 and 31 December 2006, and for the nine-month period ended and as at 30 September 2007 prepared in accordance with IFRS).

174 AUDITED AND UNAUDITED FINANCIAL INFORMATION RELATING TO HERITAGE OIL CORPORATION (HOC) PREPARED IN ACCORDANCE WITH IFRS Accountant’s report on historical consolidated financial information of Heritage Oil Corporation

KPMG LLP 8 Salisbury Square, London, EC4Y 8BB, United Kingdom

The Directors Heritage Oil Limited Ordnance House 31 Pier Road St. Helier Jersey JE4 8PW, Channel Islands Dear Sirs

Heritage Oil Corporation (‘‘HOC’’) We report on the financial information set out on pages 177 to 220 in relation to HOC. This financial information has been prepared for inclusion in the prospectus that will be dated 28 March 2008 of the Company on the basis of the accounting policies set out in note 1. This report is required by paragraph 20.1 of Annex I of the Prospectus Directive Regulation and is given for the purpose of complying with that paragraph and for no other purpose.

Responsibilities The Directors of HOC are responsible for preparing the financial information on the basis of preparation set out in note 1 to the financial information and in accordance with International Financial Reporting Standards (IFRS). It is our responsibility to form an opinion on the financial information and to report our opinion to you. Save for any responsibility arising under Prospectus Rule 5.5.3R (2)(f) to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to its inclusion in the prospectus.

Opinion In our opinion, the financial information gives, for the purposes of the prospectus dated 28 March 2008, a true and fair view of the state of affairs of HOC as at the dates stated and of its losses, cash flows and

175 recognised income and expense for the periods then ended in accordance with the basis of preparation set out in note 1 and in accordance with IFRS as described in note 1.

Declaration For the purposes of Prospectus Rule 5.5.3R (2)(f) we are responsible for this report as part of the prospectus and declare that we have taken all reasonable care to ensure that the information contained in this report is, to the best of our knowledge, in accordance with the facts and contains no omission likely to affect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 of Annex I of the Prospectus Directive Regulation. Yours faithfully

(Signed) ‘‘KPMG LLP’’ KPMG LLP 28 March 2008

176 HERITAGE OIL CORPORATION CONSOLIDATED BALANCE SHEETS

31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) ASSETS Non-current assets Assets held for sale (note 8) ...... — — 16,962,091 — Intangible exploration assets (note 10) ...... 43,503,704 54,767,332 45,602,140 85,746,870 Intangible development costs (note 11) ...... 1,187,371 1,574,039 1,346,858 — Property, plant and equipment (note 12) ...... 25,282,552 32,187,098 25,546,939 59,105,312 Other financial assets (note 13) ...... — 914,558 — 4,200,909 69,973,627 89,443,027 89,458,028 149,053,091 Current assets Assets held for sale (note 8) ...... — — 425,412 — Inventories ...... 251,915 98,921 211,510 79,768 Prepaid expenses ...... 219,222 531,273 515,899 340,402 Trade and other receivables (note 14) ...... 1,318,450 9,839,506 664,953 6,455,303 Cash and cash equivalents (note 15) ...... 8,583,321 46,861,146 46,851,571 61,894,711 10,372,908 57,330,846 48,669,345 68,770,184 80,346,535 146,773,873 138,127,373 217,823,275

LIABILITIES Current liabilities Trade and other payables (note 16) ...... 4,438,649 12,715,381 9,396,651 15,781,606 Borrowings (note 17) ...... 248,045 147,720 140,352 160,224 Liabilities of disposal group held for sale (note 8) ...... — — 807,208 — 4,686,694 12,863,101 10,344,211 15,941,830 Non-current liabilities Borrowings (note 17) ...... 7,520,438 63,124,843 62,512,234 144,918,765 Derivative financial liability (note 23) ...... — 27,997,140 8,621,068 32,810,103 Provisions (note 18) ...... 434,849 62,322 — 133,274 Liabilities of disposal group held for sale (note 8) ...... — — 419,770 — 7,955,287 91,184,305 71,553,072 177,862,142 12,641,981 104,047,406 81,897,283 193,803,972 67,704,554 42,726,467 56,230,090 24,019,303

SHAREHOLDERS’ EQUITY ATTRIBUTABLE TO EQUITY HOLDERS OF THE CORPORATION Share capital (note 19) ...... 22,854,418 24,580,984 23,508,025 40,910,098 Reserves (note 20) ...... 973,956 2,637,058 1,363,795 35,083,262 Retained earnings (deficit) (note 20) ...... 43,876,180 15,508,425 31,358,270 (51,974,057) 67,704,554 42,726,467 56,230,090 24,019,303

177 HERITAGE OIL CORPORATION CONSOLIDATED INCOME STATEMENTS

Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Revenue Petroleum and natural gas ...... 841,766 3,938,512 2,984,091 2,843,053 Drilling services ...... 342,359 2,895,727 2,491,339 — 1,184,125 6,834,239 5,475,430 2,843,053

Expenses Petroleum and natural gas operating ...... 465,110 723,611 516,868 1,814,335 Drilling rig operating ...... 196,804 2,291,585 1,912,123 38,360 General and administrative (note 7) ...... 5,706,396 8,628,127 5,446,010 31,331,031 Foreign exchange losses (gains) ...... 1,170,906 627,005 449,507 (76,493) Depletion, depreciation and amortisation ..... 738,630 1,351,987 948,477 1,306,131 Exploration expenditure (note 1 e) ...... 4,517,411 6,066,977 3,373,024 4,937,595 Impairment of property, plant and equipment (note 12) ...... ———1,799,762 12,795,257 19,689,292 12,646,009 41,150,721 Gain on disposal of subsidiaries (note 9) .....———1,077,132 Finance income (costs) Interest income ...... 330,290 1,336,351 985,353 1,243,305 Loss on redemption of liability component of convertible bonds (note 17) ...... ———(7,155,622) Loss on derivative financial liability relating to convertible bonds (note 23) ...... — (24,851,295) (5,483,503) (17,350,077) Other finance costs (note 5) ...... (491,824) (4,642,126) (3,266,497) (7,052,903) Unrealised gain on other financial assets (note 13) ...... — 195,178 — 63,351 (161,534) (27,961,892) (7,764,647) (30,251,946) Loss from continuing operations ...... (11,772,666) (40,816,945) (14,935,226) (67,482,482) Gain on disposal of discontinued operations (note 8) ...... — 9,200,700 — — Earnings from discontinued operations (note 8) 3,510,441 3,248,490 2,417,316 — Income from 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 loss per share from continuing operations Basic and diluted ...... (0.54) (1.86) (0.68) (3.02) Net earnings per share from discontinued operations Basic and diluted ...... 0.16 0.57 0.11 — Net loss per share Basic and diluted ...... (0.38) (1.29) (0.57) (3.02)

178 HERITAGE OIL CORPORATION CONSOLIDATED STATEMENTS OF RECOGNISED INCOME AND EXPENSE

Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Changes in the fair value of available-for-sale financial assets ...... — — — 168,000 Exchange differences on translation of foreign operations ...... — (4,003) — 137,771 Net income (expense) recognised directly in equity ...... — (4,003) — 305,771 Net loss for the period ...... (8,262,225) (28,367,755) (12,517,910) (67,482,482) Total recognised income and expense for the period ...... (8,262,225) (28,371,758) (12,517,910) (67,176,711)

179 HERITAGE OIL CORPORATION CONSOLIDATED CASH FLOW STATEMENTS

Nine-month periods ended Years ended 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Cash provided by (used in) Operating activities Net loss from continuing operations for the period ..... (11,772,666) (40,816,945) (14,935,226) (67,482,482) Items not affecting cash Depletion, depreciation and amortisation ...... 738,630 1,351,987 948,477 1,306,131 Finance costs—accretion expenses ...... — 647,453 453,025 1,293,845 Foreign exchange losses (gains) ...... 480,253 422,648 314,022 (327,671) Share-based compensation ...... 1,082,112 1,417,044 441,254 25,055,502 Loss on redemption of convertible bonds ...... ———7,155,622 Loss on derivative financial liability ...... — 24,851,295 5,483,503 17,350,077 Gain on disposal of subsidiaries ...... — — — (1,077,132) Gain on other financial assets ...... — (195,178) — (63,351) Impairment of property, plant and equipment ...... — — — 1,799,762 (Increase) decrease in trade and other receivables .... (258,398) (972,251) 50,157 5,412,051 (Increase) decrease in prepaid expenses ...... 1,921,678 (312,051) (296,676) 212,970 (Increase) decrease in inventory ...... (98,878) 142,809 90,763 (54,946) Increase (decrease) in trade and other payables ...... 52,946 725,738 (880,692) 2,206,961 Continuing operations ...... (7,854,323) (12,737,451) (8,331,393) (7,212,661) Discontinued operations ...... 4,034,035 3,748,853 4,403,572 — (3,820,288) (8,988,598) (3,927,821) (7,212,661)

Investing activities Property, plant and equipment expenditures ...... (2,568,064) (12,265,063) (6,100,791) (11,251,866) Intangible exploration expenditures ...... (9,204,297) (16,172,102) (5,814,624) (42,018,779) Intangible development expenditures ...... (174,359) (386,668) (159,487) (64,931) Investment in shares ...... ———(200,000) Continuing operations ...... (11,946,720) (28,823,833) (12,074,902) (53,535,576) Discontinued operations ...... 279,782 17,576,116 (3,393,977) — (11,666,938) (11,247,717) (15,468,879) (53,535,576)

Financing activities Shares issued for cash ...... 1,423,011 1,318,945 602,193 198,926 Convertible bonds ...... — 60,000,000 60,000,000 165,000,000 Convertible bonds issue costs ...... — (3,000,000) (3,000,000) (6,979,268) Redemption of convertible bonds ...... — — — (83,022,752) Long-term debt ...... 8,577,350 — — — Purchase of Common Shares for cancellation (notes 19 a) and 20 b)) ...... (876,217) — — — Repayment of long-term debt ...... (103,997) (287,759) (245,724) (116,834) 9,020,147 58,031,186 57,356,469 75,080,072 (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) 482,954 308,481 701,730 Cash and cash equivalents—End of period ...... 8,583,321 46,861,146 46,851,571 61,894,711

Non-cash investing and financing activities (note 26) Supplementary information The following have been included within cash flows from continuing operations for the period under operating activities Interest received ...... 397,640 1,665,998 1,235,166 2,354,886 Interest paid ...... 491,824 5,032,919 3,391,392 8,404,891

180 HERITAGE OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL INFORMATION Heritage Oil Corporation (the ‘‘Corporation’’) is incorporated under the Business Corporations Act (Alberta) and its primary business activity is the exploration, development and production of petroleum and natural gas in Africa, Russia, South Asia and the Middle East. These consolidated financial statements include the results of the Corporation and all subsidiaries over which the Corporation exercises control. The subsidiaries consolidated within these financial statements include inter-alia Heritage Oil & Gas Limited, Eagle Energy (Oman) Limited, Heritage Oil and Gas (U) Limited, Heritage Energy Middle East Limited, Heritage DRC Limited, Coatbridge Estates Limited, ChumpassNefteDobycha, Neftyanaya Geologicheskaya Kompaniya, Heritage Oil & Gas (Austria) GesmbH, Heritage Mali Block 7 Limited, Heritage Mali Block 11 Limited, Heritage Energy Holding GesmbH (Austria), Heritage Oil & Gas (Gibraltar) Limited, TISE-Heritage Neftegaz (Russia), Begal Air Limited, Heritage I.E. Heritage International Holding GmbH, Heritage Talinskoye GmbH, Heritage Oil & Gas Holdings Limited, Eagle Drill Limited, Heritage Oil (Barbados) Limited, Heritage Oil & Gas (Switzerland) SA and Heritage International Holding (Gibraltar) Limited. The Corporation’s consolidated financial statements are presented in U.S. dollars, which is the Corporation’s functional and presentation currency. The Corporation’s financial statements have historically been drawn up to 31 December. In February 2008, the Corporation announced that it will enter into a corporate reorganisation which will result in a newly incorporated company, Heritage Oil Limited (‘‘Heritage Jersey’’), becoming the parent company of the Corporation and its current subsidiaries. Heritage Jersey will be seeking to list its ordinary shares on the Official List of the United Kingdom Listing Authority and to trading on the Main Market of the London Stock Exchange plc (the ‘‘LSE’’). The Corporation intends to delist its existing Common Shares from the Toronto Stock Exchange (the ‘‘TSX’’) and obtain a listing for a new class of exchangeable shares on the TSX and the LSE. This financial information has been prepared for inclusion in the prospectus of Heritage Jersey to be dated 31 March 2008. In order to meet the requirements relating to the age of financial information to be included in the prospectus, the financial information has been drawn up to 30 September 2007 and comparative information has been provided for the period ended 30 September 2006 on an unaudited basis. The financial statements were approved by the Board and authorized for issuance on 28 March 2008.

1 Significant accounting policies The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the periods presented, unless otherwise stated. a) Basis of preparation The consolidated financial information has been prepared in accordance with the requirements of the Listing Rules and in accordance with this basis of preparation. This basis of preparation describes how the financial information has been prepared in accordance with International Financial Reporting Standards (IFRS). These consolidated nine month financial statements of the Corporation have been prepared in accordance with IFRS for the first time. This is the first set of financial statements which have been prepared by the Corporation under IFRS. The disclosures required by IFRS 1 concerning the transition from Canadian Generally Accepted Accounting Principles (Canadian GAAP) to IFRS are set out in note 28. The consolidated financial statements have been prepared under the historical cost convention, as modified by the revaluation of certain financial assets and liabilities at fair value. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Corporation’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in note 3.

181 b) Consolidation The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of the Corporation as at 31 December 2005 and 2006 and 30 September 2006 and 2007 and the results of all subsidiaries for the periods then ended. Subsidiaries are all entities (including special purpose entities) over which the Corporation has the power to govern the financial and operating policies so as to obtain benefits from its activities generally accompanying a shareholding of more than one half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Corporation controls another entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Corporation. They are de-consolidated from the date that control ceases. The Corporation together with its subsidiaries are referred to as the Group. The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus costs directly attributable to the acquisition. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any minority interest. The excess of the cost of acquisition over the fair value of the Group’s share of the net fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognised immediately in the income statement. Inter-company transactions, balances and unrealised gains on transactions between Group entities (the Corporation and its subsidiaries) are eliminated. For the purposes of consolidation, the accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Corporation. c) Segment reporting The Corporation’s primary segment reporting format is geographical. A geographical segment is engaged in providing products or services within a particular economic environment, that are subject to risks and returns, that are different from those of segments operating in other economic environments. d) Joint Ventures The majority of exploration, development and production activities are conducted jointly with others under contractual arrangement and, accordingly, the Group only reflects its proportionate interest in such assets, liabilities, revenues and expenses. e) Exploration and evaluation expenditure The Group applies a modified full cost method of accounting for exploration and evaluation (‘E&E’) costs, having regard to the requirements of IFRS 6 ‘‘Exploration for and Evaluation of Mineral Resources’’. Under the modified full cost method of accounting, costs of exploring for and evaluating oil and gas properties are capitalised on a licence or prospect basis and the resulting assets are tested for impairment by reference to appropriate cost pools. Such cost pools are based on geographic areas and are not larger than a segment. The Group had six cost pools: Uganda, Russia, Oman, Democratic Republic of Congo (‘‘DRC’’), Pakistan and Congo during the periods under review. E&E costs related to each licence/prospect are initially capitalised within ‘‘Intangible exploration assets’’. Such E&E costs may include costs of licence acquisition, technical services and studies, seismic acquisition, exploration drilling and testing and the projected costs of retiring the assets (if any), but do not include costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to the income statement as they are incurred. Tangible assets acquired for use in E&E activities are classified as property, plant and equipment; however, to the extent that such a tangible asset is consumed in developing an intangible E&E asset, the amount reflecting that consumption is recorded as part of the cost of the intangible asset.

182 Intangible E&E assets related to each exploration licence/prospect are not depreciated and are carried forward until the existence (or otherwise) of commercial reserves has been determined. The Group’s definition of commercial reserves for such purpose is proven and probable reserves on an entitlement basis. Proven and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty (see below) to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable and a 50 per cent statistical probability that it will be less. The equivalent statistical probabilities for the proven component of proven and probable reserves are 90 per cent and 10 percent, respectively. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: – a reasonable assessment of the future economics of such production; – a reasonable expectation that there is a market for all or substantially all the expected hydrocarbon production; and – evidence that the necessary production, transmission and transportation facilities are available or can be made available. Furthermore: (i) Reserves may only be considered proven and probable if producibility is supported by either actual production or conclusive formation test. The area of reservoir considered proven includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proven and probable classification when successful testing by a pilot project, the operation of an installed programme in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or programme was based. If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a cost pool basis as set out below and any impairment loss is recognised in the income statement. The carrying value, after any impairment loss, of the relevant E&E assets is then reclassified as development and production assets within property, plant and equipment. E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. Such indicators include the point at which a determination is made as to whether or not commercial reserves exist. Where the E&E assets concerned fall within the scope of an established full cost pool, the E&E assets are tested for impairment together with all development and production assets associated with that cost pool, as a single cash generating unit. The aggregate carrying value is compared against the expected recoverable amount of the pool, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves. Where the E&E assets to be tested fall outside the scope of any established cost pool, there will generally be no commercial reserves and the E&E assets concerned will be written off in full. f) Property, plant and equipment Development and production assets The Group had three cost pools at the development and production stage: Congo, Russia and Oman during the period under review.

183 Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above and the projected cost of retiring the assets. The net book values of producing assets are depleted on a field-by-field basis using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves of the field, taking into account estimated future development expenditures necessary to bring those reserves into production. An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit, generally by reference to the present value of the future net cash flows expected to be derived from the production of commercial reserves. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash generating unit where the cash flows generated by the fields are interdependent. Other assets Other property, plant and equipment are stated at cost less accumulated depreciation and any impairment in value. The assets’ useful lives and residual values are assessed on an annual basis. Furniture and fittings are depreciated using the reducing balance method at 20% per year. Land is not subject to depreciation. Drilling rig equipment is depreciated using the unit-of-production method based on 2,740 drilling days with a 20% residual value. The corporate jet is depreciated over its expected useful life of 69 months. Depreciation is charged so as to write off the cost, less estimated residual value of corporate jet on a straight-line basis. Corporate capital assets are depreciated on a straight-line basis over their estimated useful lives. The building is depreciated on a straight-line basis over 40 years. g) Cash and cash equivalents Cash and cash equivalents includes cash on hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less. Cash and cash equivalents are stated at amortised cost using the effective interest rate method. h) Trade and other receivables Trade and other receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of the receivables. i) Inventories Inventories consist of petroleum, condensate, liquid petroleum gas and materials that are recorded at the lower of weighted average cost and net realisable value. Cost comprises direct materials, direct labour and those overheads that have been incurred in bringing the inventories to their present location and condition. Net realisable value is the estimated selling price in the ordinary course of business, less applicable variable selling expenses. Provision is made for obsolete, slow-moving or defective items where appropriate. j) Intangible development costs Development costs are recognised as intangible assets when it is probable that the project will, after considering its commercial and technical feasibility, be completed and generate future economic benefits and its costs can be measured reliably. All other research and development costs are charged to earnings in the period incurred.

184 k) Investments The Group classifies its investments in the following categories: financial assets at fair value through the income statement and available for sale financial assets. The classification depends on the purpose for which the investments were acquired. Management determines the classification of its investments at initial recognition. During the period covered by these financial statements the Group did not have any investments classified as ‘loans and receivables’ or ‘held to maturity investments’. Financial assets at fair value through the income statement Financial assets held for trading are carried at fair value with changes in fair value recognised in the income statement. A financial asset is classified in this category if acquired principally for the purpose of selling in the short term. Derivatives are classified as held for trading unless they are designated as hedges. Gains or losses arising from changes in the fair value of the ‘financial assets at fair value through the income statement’ category are presented in the income statement within ‘Unrealised gains/ (losses) on other financial assets’ in the period in which they arise. Available-for-sale financial assets Available-for-sale financial assets, comprising principally marketable equity securities, are non-derivatives that are either designated in this category or not classified. They are included in non-current assets unless management intends to dispose of the investment within 12 months of the balance sheet date. Changes in the fair value of monetary and non-monetary securities classified as available-for-sale (other than impairment losses and foreign exchange gains and losses which are recognised in the income statement) are recognised in equity. Upon sale of a security classified as available-for-sale, the cumulative gain or loss previously recognised in equity is recognised in the income statement. The Group assesses at each balance sheet date whether there is objective evidence that a financial asset or a group of financial assets is impaired. Measurement is assessed by reference to the fair value of the financial asset or group of financial assets. l) Non-current assets held for sale (i) Assets held for sale Non-current assets (or disposal groups) are classified as assets held for sale and stated at the lower of their carrying amount and fair value less costs to sell if their carrying amount will be recovered principally through a sale transaction rather than through continuing use. Non-current assets (including those that are part of a disposal group) are not depreciated or amortised while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognised. Non-current assets classified as held for sale and the assets of a disposal group classified as assets held for sale are presented separately, as current assets, from the other assets in the balance sheet. The liabilities of a disposal group classified as held for sale are presented separately, as current liabilities, from other liabilities in the balance sheet. (ii) Discontinued operations A discontinued operation is a component of the Group that has been disposed of or is classified as held for sale and represents a separate major line of business or geographical area of operations, or is part of a single coordinated plan to dispose of such a line of business or area of operations, or is a subsidiary acquired exclusively with a view to resale. The earnings from discontinued operations are presented separately on the face of the income statement. m) Trade and other payables These amounts represent liabilities for goods and services provided to the Group prior to the end of the financial period which are unpaid.

185 n) Borrowings Borrowings are initially recognised at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortised cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in the income statement over the period of the borrowings using the effective interest method. Convertible bonds are separated into liability and derivative liability components (being the bondholders’ conversion option) and each component is recognised separately. On initial recognition, the fair value of the liability component of a convertible bond is determined using a market interest rate for an equivalent non convertible bond. This amount is recorded as a liability on an amortised cost basis using the effective interest method until extinguished on conversion or maturity of the bonds. The fair value of the derivative liability component (see also 1 (q)) is determined using a Black-Scholes option-pricing model, and this amount is recorded as a liability. Borrowings are removed from the balance sheet when the obligation specified in the contract is discharged, cancelled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in finance income or costs. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the balance sheet date. o) Borrowing costs Borrowing costs incurred for the construction of any qualifying asset are capitalised during the period of time that is required to complete and prepare the asset for its intended use or sale. Other borrowing costs are expensed. The capitalisation rate used to determine the amount of borrowing costs to be capitalised is the weighted average interest rate applicable to the Group’s outstanding borrowings during the period. For the period ended 30 September 2007, this was 10.24% (31 December 2006—2.64%; 30 September 2006—2.97%; 31 December 2005—nil%). p) Provisions Asset retirement obligations Provision is made for the estimated cost of any asset retirement obligations when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and the amount has been reliably estimated. Provisions are not recognised for future operating losses. Asset retirement obligation expense is capitalised in the relevant asset category unless it arises from the normal course of production activities. Provisions are measured at the present value of management’s best estimate of expenditure required to settle the present obligation at the balance sheet date. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognised as finance costs whereas increase due to changes in the estimated future cash flows are capitalised. q) Derivative financial liabilities Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured to their fair value at each reporting date. Changes in the fair value are recognised immediately in the income statement. r) Revenue recognition Revenue from the sale of petroleum and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer. For sales of oil and gas this is

186 usually when legal title passes to the external party. Interest income is recognised on a time proportion basis using the effective interest method. Drilling services revenue relates to the provision of drilling services in respect of the drilling rig. s) Income taxes Current income tax is based on taxable profit for the period. Taxable profit differs from profit as reported in the income statement because it excludes items that are never taxable or deductible. The Group’s current tax assets and liabilities are calculated using tax rates that have been enacted or substantively enacted by the balance sheet date. Deferred income tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the deferred tax balances relate to the same taxation authority. t) Foreign currency translation Items included in the financial statements of each of the Corporation’s consolidated subsidiaries are measured using the currency of the primary economic environment in which the subsidiary operates (‘the functional currency’). The Corporation’s consolidated financial statements are presented in U.S. dollars, which is the Corporation’s functional and presentation currency. Foreign currency transactions are translated into the respective functional currencies of group entities using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement, except when they are deferred in equity as part of or as a hedge of the net investment in a foreign operation. The results and financial position of all the Corporation’s consolidated subsidiaries (none of which has a functional currency that is the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows: i) assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet; ii) income and expenses for each period are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and iii) all resulting exchange differences are recognised as income and expense in a separate component of equity. Foreign currency loans and overdrafts are designated as and are considered to be hedges of the exchange rate exposure inherent in foreign currency net investments and, to the extent that the hedge is effective, exchange differences giving rise to changes in the carrying value of foreign currency loans are also recognised as income or expense directly in equity. All other exchange differences giving rise to changes in the carrying value of foreign currency loans and overdrafts are recognised in the income statement. When a foreign operation is sold or any borrowings hedging forming part of the net investment are repaid, a proportionate share of the cumulative exchange differences previously recognised in

187 equity are recognised in the income statement, as part of the gain or loss on sale where applicable. u) Share-based compensation plans The Group applies the fair value method of accounting to all equity-classified stock-based compensation arrangements for both employees and non-employees. Compensation cost of equity-classified awards to employees are measured at fair value at the grant date and recognised over their vesting period with a corresponding increase in equity. The amount recognised as an expense is adjusted to reflect the actual number of share options that vest. The compensation cost of equity-classified awards to non-employees is initially measured at fair value, and periodically remeasured to fair value until the non-employees’ performance is complete, and recognised over their vesting period with a corresponding increase to contributed surplus. Upon the exercise of the award, consideration received is recognised in equity. v) Share capital Common Shares are classified as share capital. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from the proceeds. If the Corporation reacquires its own equity instruments the cost is deducted from equity and the associated shares are cancelled. w) Earnings per share Basic earnings per share is calculated by dividing the profit attributable to equity holders of the Corporation by the weighted average number of Common Shares outstanding during the financial period. Diluted earnings per share adjusts the figures used in the determination of basic earnings per share to take into account the after income tax effect of interest and other financing costs associated with dilutive potential Common Shares and the weighted average number of shares assumed to have been issued for no consideration in relation to dilutive potential Common Shares. The if-converted method used in the calculation of diluted earnings per share assumes the conversion of convertible securities at the later of the beginning of the reported period or issuance date, if dilutive. x) New accounting standards and interpretations Certain new accounting standards and interpretations have been published that are not mandatory for the 30 September 2007 reporting period. The Corporation’s assessment of the impact of these new standards and interpretations which have not been adopted is set out below. i) IFRS 8, ‘‘Operating segments’’ (effective from 1 January 2009), replaces IAS 14 and aligns segment reporting with the requirements of the US standard SFAS 131, ‘‘Disclosures about segments of an enterprise and related information’’. The new standard requires a ‘‘management approach’’, under which segment information is presented on the same basis as that used for internal reporting purposes. The expected impact is still being assessed by management, but is expected to only impact the disclosures of the Group. The following standards are assessed not to have any impact on the Corporation’s financial statements: i) IAS 23 (Amendment), ‘‘Borrowing costs’’ (effective from 1 January 2009), requires the Group to capitalise borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset (one that takes a substantial period of time to get ready for use or sale) as part of the cost of that asset. The Group currently applies the capitalisation approach to borrowing costs. ii) IFRIC 11, ‘‘IFRS 2—Group and treasury share transactions’’ (effective from 1 January 2008), provides guidance on whether share-based transactions involving treasury shares or involving group entities (for example, options over a parent’s shares) should be accounted for as equity-settled or cash-settled share-based payment transactions in the stand-alone accounts of the parent and group companies.

188 iii) IFRIC 12, ‘‘Service concession arrangements’’ (effective from 1 January 2008), applies to contractual arrangements whereby a private sector operator participates in the development, financing, operation and maintenance of infrastructure for public sector services. iv) IFRIC 13, ‘‘Customer loyalty programmes’’ (effective from 1 July 2008), clarifies that where goods or services are sold together with a customer loyalty incentive (for example, loyalty points or free products), the arrangement is a multiple-element arrangement and the consideration receivable from the customer is allocated between the components of the arrangement using fair values. v) IFRIC 14, ‘‘IAS 19—The limit on a defined benefit asset, minimum funding requirements and their interaction’’ (effective from 1 January 2008), provides guidance on assessing the limit in IAS 19 on the amount of the surplus that can be recognised as an asset. It also explains how the pension asset or liability may be affected by a statutory or contractual minimum funding requirement. The following amendments have been published, but have not been applied in these financial statements: i) IFRS 2 (Amendment), Share based payment—Vesting Conditions and Cancellations: effective for accounting periods commencing on or after 1 January 2009; i) IFRS 3 (Amendment) Business Combinations: effective for accounting periods commencing on or after 1 July 2009; iii) IAS 1 (Amendment), Presentation of Financial Statements: effective for accounting periods commencing on or after 1 January 2009; iv) IAS 23 (Amendment), Borrowing Costs: effective for accounting periods commencing on or after 1 January 2009; v) IAS 27 (Amendment), Consolidated and Separate Financial Statements: effective for accounting periods commencing on or after 1 July 2009. The Directors do not anticipate that the adoption of these amendments will have a material impact on the Group’s financial statements in the period of initial application.

2 Risk management The Group’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities. The Group’s overall risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group’s financial performance. a) Financial risk management i) Foreign exchange risk Foreign exchange risk arises when transactions and recognised assets and liabilities of the Group entity concerned are denominated in a currency that is not the Corporation’s functional currency. The Group operates internationally and is exposed to foreign exchange risk arising from currency exposures to the U.S. dollar. There are no forward exchange rate contracts in place at, or subsequent to, 30 September 2007. At 30 September 2007, if the Canadian dollar had strengthened/weakened by 10% against the U.S. dollar with all other variables held constant, the loss for the period would have been $2,033,068 (30 September 2006—$99,367; 31 December 2006—$125,982; 31 December 2005—$(20,937)) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Canadian dollar-denominated general and administrative expenses and cash in bank. Profit is more/less sensitive to movement of Canadian/U.S. dollar exchange rates in 2007 than 2006 because of significantly higher general and administrative expenses in 2007 in comparison with 2006. At 30 September 2007, if the Russian rouble had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss for the period would have been

189 $(106,943) (30 September 2006—$(53,228); 31 December 2006—$(236,730); 31 December 2005—$(139)) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Russian rouble-denominated cash in bank and monetary assets and liabilities. At 30 September 2007, if the GBP pound sterling had strengthened/weakened by 10% against the US dollars with all other variables held constant, the loss for the period would have been $781,534 (30 September 2006—$749,534; 31 December 2006—$730,637; 31 December 2005—$686,923) higher/(lower), mainly as a result of foreign exchange gains/ losses on translation of GBP pound sterling-denominated long-term loan. At 30 September 2007, if the Swiss franc had strengthened/weakened by 10% against the US dollar with all other variables held constant, the loss for the period would have been $(432,727) (30 September 2006—$(294,544); 31 December 2006—$(286,493); 31 December 2005—$(117,816)) higher/(lower), mainly as a result of foreign exchange gains/ losses on translation of Swiss franc-denominated cash in bank. ii) Commodity price risk The Corporation is exposed to commodity price risk to the extent that it will sell its entitlement to petroleum, condensate and liquid petroleum gas production on a floating price basis. The Corporation may consider partly mitigating this risk in the future. The table below summarises the impact of increases/decreases of the relevant oil / condensate / LPG benchmark on the Corporation’s post-tax profit or loss for the period and on equity. The analysis is based on the assumption that the commodity prices had increased / decreased by 5% with all other variables held constant:

Year ended Nine-month periods 31 December ended 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Brent light crude ...... — — — 49,227 Condensate ...... 42,088 196,926 133,812 77,831 LPG...... 17,118 144,786 15,393 15,095 59,206 341,712 149,205 142,153

Post-tax profit for the year and equity would increase/decrease as a result of commodity revenues received. iii) Interest rate risk The Group had fixed rate long-term debt and fixed rate convertible bonds in the period under review, therefore it was not exposed to interest rate risk. iv) Credit risk All of the Corporation’s production is derived from the Republic of Congo, Russia and Oman. In 2006, 2005, and for the nine-month periods ended 30 September 2007 and 2006, the Corporation sold all of its production, at any point in time, in each country to a single customer for each commodity. Accordingly, substantially all the Corporation’s accounts receivables from petroleum and natural gas sales were from a maximum of four customers during these periods. Debtors of the Corporation are subject to internal credit review to minimize the risk of non-payment. The Corporation does not anticipate any default as it transacts with creditworthy counterparties. No credit limits were exceeded during the reporting periods and management does not expect any losses from non-performance by these counterparties.

190 v) Liquidity risk Liquidity risk is the risk that the Group will not have sufficient funds to meet liabilities. Cash forecasts identifying liquidity requirements of the Group are produced quarterly. These are reviewed regularly to ensure sufficient funds exist to finance the Corporation’s current operational and investment cash flow requirements. Management monitors rolling forecasts of the Corporation’s liquidity reserve on the basis of expected cash flow. The Group had available cash at approximately $62 million at 30 September 2007. Since then it has raised approximately $186 million by way of an equity offering of Common Shares (see note 27). Based on its current plans and knowledge, its projected capital expenditure and operating cash requirements, the Group projects available cash at 31 December 2008 of approximately $122 million. The Corporation’s financial liabilities consist of trade and other payables and borrowings. Trade and other payables are due within 12 months, and borrowings fall due as outlined in note 25. b) Capital risk management The Corporation’s objectives when managing capital are to safeguard the Corporation’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Corporation monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital. Net debt is calculated as total borrowings (including ‘borrowings’ and ‘trade and other payables’ as shown in the consolidated balance sheet) less cash and cash equivalents. Total capital is calculated as ‘equity’ as shown in the consolidated balance sheet plus net debt.

As at 31 December As at 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Total borrowings ...... 12,641,981 104,047,406 81,897,283 193,803,972 Less cash and cash equivalents (note 15) ...... (8,583,321) (46,861,146) (46,851,571) (61,894,711) Net debt ...... 4,058,660 57,186,260 35,045,712 131,909,261 Total equity ...... 67,704,554 42,726,467 56,230,090 24,019,303 Total capital ...... 71,763,214 99,912,727 91,275,802 155,928,564 Gearing ratio ...... 6% 57% 38% 85%

This increase in the gearing ratio during 2006 and 2007 resulted primarily from the issuances of bonds and long-term debt (note 17).

191 3 Critical accounting estimates, assumptions and judgements In the process of applying the Corporation’s accounting policies, which are described in note 1, management makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: a) Recoverability of exploration and evaluation costs Under the modified full cost method of accounting for E&E costs, certain costs are capitalised as intangible assets by reference to appropriate cost pools, and are assessed for impairment when circumstances suggest that the carrying amount may exceed its recoverable value. Such circumstances include, but are not limited to: i) the period for which the entity has the right to explore in the specific area has expired during the period, or will expire in the near future, and is not expected to be renewed; ii) substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is neither budgeted nor planned; iii) exploration for and evaluation of mineral resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the entity has decided to discontinue such activities in the specific area; and iv) sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale. This assessment involves judgement as to (i) the likely future commerciality of the asset and when such commerciality should be determined, and (ii) future revenues and costs pertaining to any wider cost pool with which the asset in question is associated, and (iii) the discount rate to be applied to such revenues and costs for the purpose of deriving a recoverable value. Note 10 discloses the carrying amounts of the Group’s E&E assets. Consequently, major uncertainties affect the recoverability of these costs which is dependent on the Group achieving commercial production or the sale of the assets. b) Reserve estimates Estimates of recoverable quantities of proven and probable reserves include assumptions regarding commodity prices, exchange rates, discount rates, production and transportation costs for future cash flows. It also requires interpretation of complex and difficult geological and geophysical models in order to make an assessment of the size, shape, depth, and quality of reservoirs and their anticipated recoveries. The economic, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact asset carrying values and the asset retirement obligation due to changes in expected future cash flows. Reserves are integral to the amount of depletion charged to the income statement and the calculation of inventory. The level of estimated commercial reserves is also a key determinant in assessing whether the carrying value of any of the Group’s development and production assets has been impaired. c) Fair value of financial instruments The Group’s accounting policies and disclosures require the determination of the fair value of financial instruments. Fair values have been determined for measurement and/or disclosure purposes based on the following methods: i) Non-derivative financial instruments These comprise investments in equity and debt securities, trade and other receivables, cash and cash equivalents, loans and borrowings and trade and other payables. Non-derivative financial instruments are recognised initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Fair value is calculated based on the present value of future principal and interest cash flows, discounted at the applicable market rate of interest at the reporting date.

192 ii) Derivatives Derivatives are recognised initially at fair value; attributable transaction costs are recognised in the profit or loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value. Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through the income statement. The fair value of derivative financial instruments is based on their listed market prices, if available. If a listed market price is not available, then fair value is estimated by discounting the difference between the contractual forward price and the current forward price for the residual maturity of the contract using a risk-free interest rate (based on government bonds). iii) Compound financial instruments Compound financial instruments issued by the Group comprise convertible bonds that can be converted to share capital at the option of the holder, and the number of shares to be issued does not vary with changes in their fair value. The convertible bonds are separated into liability and derivative liability components (being the bondholders’ conversion option). The liability component of a compound financial instrument is recognised initially at fair value, determined by reference to market interest rates for equivalent bonds which do not contain conversion features. Subsequent to initial recognition, the liability component is measured at amortised cost using the effective interest method. The fair value of the derivative liability component is determined using a Black-Scholes option-pricing model and this amount is recorded as a liability. The Black-Scholes model contains assumptions and determinations pertaining to volatility, risk-free interest rates, and the terms of the options.

4 Segment information The Group has a single class of business which is international exploration, development and production of petroleum oil and natural gas. The Group operates in a number of geographical areas based on location of operations and assets, being Russia, Oman, Uganda, Democratic Republic of Congo (‘‘DRC’’), Congo, Iraq, and Pakistan.

Year ended 31 December 2005 Depreciation, External Segment Total Capital depletion and revenue result Total assets liabilities additions amortisation $$$$$ $ Russia ...... — (478,269) 6,087,436 6,739 6,080,697 — Oman...... 841,766 (64,698) 6,189,028 47,247 387,764 441,355 Uganda(1) ...... 342,359 145,554 27,858,240 420,905 6,323,678 — DRC...... — (35,745) 12,494 — — — Congo(2) ...... 6,499,307 3,510,441 15,089,178 434,849 2,629,596 1,110,547 Iraq ...... — (1,948,967) — — — — Pakistan ...... — (391,145) — — — — Unallocated— Corporate ...... 330,290 (8,999,396) 25,110,159 11,732,241 694,900 297,275 8,013,722 (8,262,225) 80,346,535 12,641,981 16,116,635 1,849,177

193 Year ended 31 December 2006 Depreciation, External Segment Total Capital depletion and revenue result Total assets liabilities additions amortisation $$ $ $$$ Russia ...... — (3,698) 23,395,149 150,324 12,830,190 — Oman ...... 3,938,512 716,322 10,439,341 642,607 5,226,268 807,424 Uganda(1) ...... 2,895,727 428,129 46,537,931 7,311,956 14,934,054 176,013 DRC...... — (51,552) 35,468 — 35,468 — Congo(2) ...... 5,762,283 12,449,190 5,157,646 — 2,610,699 843,562 Iraq(3) ...... — (3,556,202) — — — — Pakistan ...... — (715,776) — — — — Unallocated— Corporate ...... 1,336,351 (37,634,168) 61,208,338 95,942,519 1,510,919 368,550 13,932,873 (28,367,755) 146,773,873 104,047,406 37,147,598 2,195,549

Nine-month period ended 30 September 2006 (Unaudited) Depreciation, External Segment Total Capital depletion and revenue result Total assets liabilities additions amortisation $$ $$$$ Russia ...... — — 12,767,641 44,809 5,755,031 — Oman...... 2,984,091 1,926,052 8,757,988 589,060 4,052,188 541,171 Uganda(1) ...... 2,491,339 444,604 39,225,922 4,916,993 7,312,675 134,612 DRC...... — (51,552) 26,116 — 16,893 — Congo(2) ...... 4,485,048 2,417,316 17,387,503 1,226,978 2,610,699 843,562 Iraq(3) ...... — (2,836,603) — — — — Pakistan ...... — (436,818) — — — — Unallocated— Corporate .... 985,353 (13,980,909) 59,962,203 75,119,443 1,361,964 272,694 10,945,831 (12,517,910) 138,127,373 81,897,283 21,109,450 1,792,039

Nine-month period ended 30 September 2007 Depreciation, External Segment Total Capital depletion and revenue result Total assets liabilities additions amortisation $$ $ $ $ $ Russia ...... 984,539 (2,123,116) 38,406,629 1,010,028 15,589,608 317,688 Oman ...... 1,858,514 1,100,193 12,934,518 317,249 3,597,498 276,181 Uganda(1) ...... — (43,033) 74,148,785 7,705,785 28,316,889 — DRC...... — — 1,239,696 — 654,228 — Congo(2) ...... — — — — — — Iraq(3) ...... — (2,271,066) — — — — Pakistan ...... — (342,819) 874,855 — 874,855 — Unallocated— Corporate ...... 1,243,305 (63,937,561) 90,218,792 184,770,910 11,758,850 712,262 4,086,358 (67,617,402) 217,823,275 193,803,972 60,791,928 1,306,131

(1) Uganda includes exploration activity as well as revenue and operating profit from drilling services. (2) Revenues and expenses from Congo have been included as discontinued operations in the income statement. (3) Iraq information is not a separate geographic segment as defined in note 1(e) based on the fact that the license was not received until October 2007 (note 27). However, information was presented for clarity. Exploration expenditures in respect of E&E assets relate to pre-licence costs which are expensed in accordance with IFRS 6.

194 5 Other finance costs Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Interest on long-term debt ...... 491,824 532,918 391,392 419,898 Interest on convertible bonds ...... — 4,602,740 3,090,411 9,387,986 Accretion of convertible debt ...... — 860,895 578,029 2,652,613 Accretion of asset retirement obligation ...... — — — 5,376 491,824 5,996,553 4,059,832 12,465,873 Amount capitalised ...... — (1,354,427) (793,335) (5,412,970) Finance costs expensed ...... 491,824 4,642,126 3,266,497 7,052,903

Finance costs are capitalised in various balance sheet categories.

6 Income tax expense The Group is subject to income taxes in Canada, Uganda and Russia. All of the Group’s operating activities are outside of Canada. In Oman, the effective tax rate is nil as in this jurisdiction the Group is subject to a production sharing agreement. In Canada, Uganda and Russia, the Group has available tax deductions of $25,418,994 (31 December 2006—$14,737,369) and tax losses of $70,286,702 (31 December 2006—$54,750,658), of which $23,452,398 expires from 2008 to 2027, and the remaining $46,834,304 does not have an expiry period. No deferred tax assets have been recognised for the benefit of the Canadian tax deductions and Canadian and Russian tax losses because realisation of the deferred tax assets in the foreseeable future is not sufficiently likely. Factors affecting current tax charge for the period:

Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Net loss on ordinary activities before tax . . . (8,262,225) (28,367,755) (12,517,910) (67,482,482) Standard tax rate ...... 37.6% 34.7% 34.7% 32.3% Tax on loss at standard rate ...... (3,108,249) (9,843,611) (4,343,715) (21,796,842) Expenses not deductible for tax purposes . . . 2,878,891 10,247,124 5,218,809 20,156,056 Effect of tax losses not recognised ...... 229,358 (403,513) (875,094) 1,640,786 Current tax charge ...... ————

As at 31 December As at 30 September 2005 2006 2006 2007 $$$$ (Unaudited) The balance comprises temporary differences attributable to: Available tax losses and deductions ...... 19,107,122 19,744,609 19,273,028 23,639,376 Deferred tax asset (unrecognised) ...... 19,107,122 19,744,609 19,273,028 23,639,376

195 7 Staff costs The average number of employees (including executive directors) employed by the Group during the period, analysed by category was:

Nine-month periods Year ended ended 31 December 30 September 2005 2006 2006 2007 (Unaudited) Canada ...... — — — 1 Switzerland ...... 2 3 4 3 Russia ...... — 25 25 41 United Kingdom ...... 10 13 13 14 Uganda ...... 7 21 21 21 Kurdistan region of Iraq ...... 6 7 7 5 South Africa ...... 3 3 3 4 Total ...... 28 72 73 89

The aggregate payroll expenses of those employees was as follows:

Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Salaries and other short-term benefits ...... 5,299,861 9,726,603 5,253,099 6,481,888 Share-based compensation ...... 898,121 1,765,681 441,254 31,129,696 Total employee remuneration ...... 6,197,982 11,492,284 5,694,353 37,611,584 Capitalised portion of total remuneration ...... 1,755,893 4,211,166 1,459,838 10,890,269

Key management compensation was:

Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Salaries and other short-term benefits ...... 4,237,786 4,111,948 3,213,987 3,093,756 Share-based payments ...... 781,114 753,174 333,810 22,556,842 5,018,900 4,865,122 3,547,797 25,650,598

8 Discontinued operations On 6 June, 2006, the Group entered into an agreement to sell Heritage Congo Limited which held all of the Group’s interests in the Noumbi Exploration Permit and the Kouakouala A and B licences in the Republic of Congo (‘‘Congo’’) to Afren PLC, subject to a number of conditions precedent and pre-emption rights. During 2006, the Group’s partners in the Kouakouala A and B licences exercised their pre-emption rights in respect of the sale of these assets. Accordingly, the Group sold these assets to three separate public entities later in 2006. On 22 November, 2006, the Group completed the sale of Heritage Congo Limited, which held a 14% working interest in the Noumbi Exploration Permit, to Afren PLC (‘‘Afren’’) for the following consideration: a) Cash of $21,000,000; and b) 1,500,000 Afren warrants, with a term of five years and an exercise price of £0.60 per share. The fair value of the Afren warrants, determined by using the Black-Scholes model, was $719,380 at the date of sale (note 13). On 18 January 2007, the Group finalized the statement of adjustments relating to the sale of its 25% working interest in the Kouakouala A and 30% working interest in the Kouakouala B licence in

196 Congo to the other partners in the licences, Maurel et Prom and Burren Energy, for the following consideration: a) Cash of $6,052,515; and b) An overriding royalty of 15% over a 30% working interest in the Kouakouala B licence in relation to the Mengo field. The Mengo field is not in production. All of the disposition agreements were completed by 12 December 2006. The gain on disposal of all of the Group’s interests in the Congo was $9,200,700 in 2006. As at 31 December 2006, accounts receivable included $5,157,646 relating to the unpaid portion of the sales proceeds, which was received in January 2007. The results of operations in Congo have been classified as earnings from discontinued operations. The following table provides additional information with respect to the amounts included in the earnings from discontinued operations. Year ended Period ended Period ended 31 December 12 December 30 September 2005 2006 2006 $$ $ (Unaudited) Revenue Petroleum and natural gas ...... 5,444,936 5,116,368 3,805,505 Interest ...... 41,361 — — Other ...... 1,013,010 645,915 679,543 6,499,307 5,762,283 4,485,048

Expenses Operating ...... 991,956 902,776 653,344 Royalties ...... 816,740 767,455 570,826 Foreign exchange losses ...... 69,623 — — Depletion, depreciation and accretion ...... 1,110,547 843,562 843,562 2,988,866 2,513,793 2,067,732 3,510,441 3,248,490 2,417,316

The following table provides additional information with respect to the amounts included in the balance sheet as assets of the disposal group held for sale. 12 December 30 September 2006 2006 $$ (Unaudited) Assets Non-current assets Intangible exploration assets (note 10) ...... 8,323,966 8,323,966 Property, plant and equipment (note 12) ...... 11,638,420 8,638,125 19,962,386 16,962,091 Current Trade and other receivables ...... — 375,651 Inventories ...... — 49,761 — 425,412 19,962,386 17,387,503

Liabilities Current liabilities Trade and other payables ...... 971,421 807,208

Non-current Provisions (note 18) ...... 419,770 419,770 1,391,191 1,226,978 Net assets ...... 18,571,195 16,160,525

197 The gain on disposal of discontinued operations has been derived as follows:

31 December 2006 $ Consideration received or receivable Cash ...... 27,052,515 Warrants ...... 719,380 Total disposal consideration ...... 27,771,895 Less carrying amount of net assets sold ...... (18,571,195) Gain on disposal ...... 9,200,700

9 Disposals On 9 March 2007, the Group disposed of its previously consolidated 65% interests in Natural Pipelay Worldwide Limited (‘‘NPWL’’) and Naturalay Technologies Limited (‘‘Naturalay’’) in consideration for 605,000 common shares in a private company named SeaDragon. The fair value of the common shares consideration received of $2,420,000, which was based on the most recent private placement by SeaDragon in October 2006, resulted in a gain of $1,077,132 on the disposal. The Group’s CFO is a director and CFO of SeaDragon. Below is an analysis of the assets and liabilities of NPWL and Naturalay as at 9 March 2007, the date of sale completion:

$ Assets Intangible development costs ...... 1,642,868

Liabilities Trade and other payables ...... 300,000 Net assets ...... 1,342,868

The gain on disposal of the previously consolidated subsidiary has been derived as follows:

$ Consideration received or receivable Fair value of shares ...... 2,420,000 Total disposal consideration ...... 2,420,000 Less: carrying amount of net assets sold ...... 1,342,868 Gain on disposal of subsidiaries ...... 1,077,132

10 Intangible exploration assets 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Balance—Beginning of period ...... 32,725,642 43,503,704 43,503,704 54,767,332 Exchange differences ...... — 64,121 36,270 117,189 Additions ...... 10,778,062 20,656,473 11,519,132 40,355,455 Assets transferred to property, plant and equipment (note 12) ...... — (1,133,000) (1,133,000) (9,493,106) Assets transferred to disposal group held for sale (note 8) ...... — (8,323,966) (8,323,966) — Balance — End of period ...... 43,503,704 54,767,332 45,602,140 85,746,870

198 No assets have been pledged as security. The balances at the end of the periods are as follows:

31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Russia ...... 4,612,321 6,437,022 5,979,541 14,066,855 Oman...... 3,875,880 7,048,524 5,897,554 552,257 Uganda ...... 27,163,615 41,246,318 33,708,152 69,563,207 DRC...... — 35,468 16,893 689,696 Congo ...... 7,851,888 — — — Pakistan ...... ———874,855 Balance — End of period ...... 43,503,704 54,767,332 45,602,140 85,746,870

11 Intangible development costs 31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Cost ...... 1,187,371 1,574,039 1,346,858 — Accumulated amortisation ...... — — — — Net book amount ...... 1,187,371 1,574,039 1,346,858 — Net book amount—Beginning of period ...... 1,013,012 1,187,371 1,187,371 1,574,039 Additions—Internal development ...... 174,359 386,668 159,487 68,829 Disposals—Sale of subsidiaries (note 9) ...... — — — (1,642,868) Net book amount—End of period ...... 1,187,371 1,574,039 1,346,858 —

Intangible development costs, such as personnel and production expenses, are related to the development of the Buoyant Drum Lay System (‘‘Pipelay System’’). As the Pipelay System development was not complete, amortisation had not yet commenced before the disposal of the subsidiaries.

199 12 Property, plant and equipment

31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Petroleum and natural gas interests ...... 13,255,901 18,091,216 11,349,845 36,328,564 Drilling equipment ...... 2,693,618 3,544,969 3,461,756 3,544,969 Land and building ...... 11,984,701 11,984,701 11,984,701 11,984,701 Other ...... 1,176,671 2,687,590 2,538,635 14,446,440 Property, plant and equipment, at cost ...... 29,110,891 36,308,476 29,334,937 66,304,674 Accumulated depletion and depreciation ..... (3,828,339) (4,121,378) (3,787,998) (7,199,362) Net book amount ...... 25,282,552 32,187,098 25,546,939 59,105,312

Reconciliation of movements during the period Petroleum and natural gas interests Cost—Beginning of period ...... 9,250,840 13,255,901 13,255,901 18,091,216 Accumulated depletion and depreciation— Beginning of period ...... (1,803,668) (3,303,490) (3,303,490) (3,051,966) Net book amount—Beginning of period ...... 7,447,172 9,952,411 9,952,411 15,039,250 Net book value—Beginning of period ...... 7,447,172 9,952,411 9,952,411 15,039,250 Exchange differences ...... — 103,065 30,333 136,216 Additions ...... 4,005,061 14,128,855 7,460,216 8,608,026 Assets transferred from intangible exploration (note 10) ...... — 1,133,000 1,133,000 9,493,106 Assets transferred to discontinued operations (note 8) ...... — (8,638,125) (8,638,125) — Depletion and depreciation ...... (1,499,822) (1,639,956) (1,443,833) (565,961) Net book amount—End of period ...... 9,952,411 15,039,250 8,494,002 32,710,637 Cost—End of period ...... 13,255,901 18,091,216 11,349,845 36,328,564 Accumulated depletion and depreciation—End of period ...... (3,303,490) (3,051,966) (2,855,843) (3,617,927) Net book amount—End of period ...... 9,952,411 15,039,250 8,494,002 32,710,637

Drilling and barge equipment Cost—Beginning of period ...... 2,055,006 2,693,618 2,693,618 3,544,969 Accumulated depletion and depreciation— Beginning of period ...... (135,898) (171,728) (171,728) (347,741) Net book amount—Beginning of period ...... 1,919,108 2,521,890 2,521,890 3,197,228

Net book amount—Beginning of period ..... 1,919,108 2,521,890 2,521,890 3,197,228 Additions ...... 638,612 851,351 768,138 — Depletion and depreciation ...... (35,830) (176,013) (134,612) — Impairment ...... ———(1,799,762) Net book amount—End of period ...... 2,521,890 3,197,228 3,155,416 1,397,466

Cost—End of period ...... 2,693,618 3,544,969 3,461,756 3,544,969 Accumulated depletion and depreciation—End of period ...... (171,728) (347,741) (306,340) (2,147,503) Net book amount—End of period ...... 2,521,890 3,197,228 3,155,416 1,397,466

200 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Land and building Cost—Beginning of period ...... 11,984,701 11,984,701 11,984,701 11,984,701 Accumulated depletion and depreciation— Beginning of period ...... (34,795) (173,973) (173,973) (313,151) Net book amount—Beginning of period ...... 11,949,906 11,810,728 11,810,728 11,671,550

Net book amount—Beginning of period ..... 11,949,906 11,810,728 11,810,728 11,671,550 Depletion and depreciation ...... (139,178) (139,178) (104,384) (104,383) Net book amount—End of period ...... 11,810,728 11,671,550 11,706,344 11,567,167

Cost—End of period ...... 11,984,701 11,984,701 11,984,701 11,984,701 Accumulated depletion and depreciation—End of period ...... (173,973) (313,151) (278,357) (417,534) Net book amount—End of period ...... 11,810,728 11,671,550 11,706,344 11,567,167

Other Cost—Beginning of period ...... 481,771 1,176,671 1,176,671 2,687,590 Accumulated depletion and depreciation— Beginning of period ...... (21,051) (179,148) (179,148) (408,520) Net book amount—Beginning of period ...... 460,720 997,523 997,523 2,279,070 Net book amount—Beginning of period ..... 460,720 997,523 997,523 2,279,070 Additions ...... 694,900 1,510,919 1,361,964 11,758,850 Depletion and depreciation ...... (158,097) (229,372) (168,310) (607,878) Net book amount—End of period ...... 997,523 2,279,070 2,191,177 13,430,042 Cost—End of period ...... 1,176,671 2,687,590 2,538,635 14,446,440 Accumulated depletion and depreciation—End of period ...... (179,148) (408,520) (347,458) (1,016,398) Net book amount—End of period ...... 997,523 2,279,070 2,191,177 13,430,042

The corporate office which represents the land and building category serves as security for a long-term loan (note 17). The carrying value of the drilling rig was written down to its estimated fair value based on third-part quoted sales prices. This resulted in an impairment write-down of $1,799,762 recognised in the income statement during the nine-month period ended 30 September 2007.

13 Other financial assets

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Investment in warrants ...... — 914,558 — 977,909 Investment in unlisted securities ...... — — — 3,223,000 — 914,558 — 4,200,909

The investment in Afren warrants (note 8) is classified as held for trading. The investment in unlisted securities represents common shares in a private company named SeaDragon (note 9), which is classified as available-for-sale. There were no other disposals (see note 9) or impairment losses on held for trading or available-for-sale financial assets in the reporting periods under these financial statements.

201 The fair value of unlisted shares of SeaDragon is based on the most recent private placement of SeaDragon on 26 October 2006. The Directors consider that there has been no change in the fair value of these shares since this date.

14 Trade and other receivables

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Trade receivables ...... 879,163 890,662 152,526 551,270 Other receivables ...... 439,287 8,948,844 512,427 5,904,033 1,318,450 9,839,506 664,953 6,455,303

Trade and other receivables are due within 30 days from the invoice date. No interest is charged on the receivables. The carrying amount of trade and other receivables approximates their fair value. The maximum exposure to credit risk at the reporting date is the fair value of each class of receivable. As of 30 September 2007, trade receivables of $6,455,303 (30 September 2006—$664,953; 31 December 2006—$9,839,506; 31 December 2005—$1,318,450) were neither past due nor impaired. These relate to a number of independent customers for whom there is no recent history of default. The ageing analysis of these trade and other receivables is as follows:

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Up to 3 months ...... 1,318,450 9,703,000 656,204 5,118,597 3 to 6 months ...... — 136,506 8,749 1,336,706 1,318,450 9,839,506 664,953 6,455,303

Trade and other receivables analysed by category are as follows:

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) U.S. dollars ...... 1,230,410 7,970,228 253,883 5,148,165 GBP pounds sterling ...... — 24,040 — 24,040 Russian roubles ...... — 1,495,891 286,096 821,128 Swiss francs ...... 88,040 349,347 124,974 461,970 1,318,450 9,839,506 664,953 6,455,303

15 Cash and cash equivalents

31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Cash at bank and in hand ...... 8,583,321 46,861,146 46,851,571 61,894,711

Cash at bank and in hand includes cash held in interest bearing accounts.

202 16 Trade and other payables

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Trade payables ...... 1,995,384 9,253,320 6,929,625 10,669,952 Other payables and accrued liabilities ...... 2,443,265 3,462,061 2,467,026 5,111,654 4,438,649 12,715,381 9,396,651 15,781,606

Trade and other payables and accrued liabilities comprise current amounts outstanding for trade purchases and ongoing costs. The carrying amount of trade and other payables approximates their fair value.

17 Borrowings

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Non-current borrowings Convertible bonds—unsecured ...... — 54,715,050 54,440,464 136,264,249 Non-current portion of long-term debt ...... 7,520,438 8,409,793 8,071,770 8,654,516 7,520,438 63,124,843 62,512,234 144,918,765

Long-term debt—secured Current ...... 248,045 147,720 140,352 160,224 Non-current ...... 7,520,438 8,409,793 8,071,770 8,654,516 7,768,483 8,557,513 8,212,122 8,814,740

2006 convertible bonds On 27 March 2006, the Corporation issued 600 unsecured convertible bonds each with a par value of $100,000 for aggregate proceeds of $60,000,000. Issue costs amounted to $3,000,000 resulting in net proceeds of $57,000,000. The bonds bear a coupon rate of 10% per annum and a term of five years and one day. On maturity, any bonds outstanding are redeemed for cash. At the option of the holders, the bonds are convertible, in whole or in part, into Common Shares at a price of U.S.$18.00 per share at any time during the term of the bonds. The Corporation could 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. Pursuant to the bond agreement, the Group is required to maintain an equity to debt, net of cash and cash equivalent, ratio of no less than 0.65:1.00. The proceeds of the bond can be employed for development of the Zapadno Chumpasskoye field in Russia and for general corporate purposes. The bonds included conversion features which in certain circumstances could be settled in cash and so these features represent a derivative financial instrument which is classified as a liability. The fair value of the liability component of the bonds (net of issue costs) was estimated at $53,862,435. The fair value of the derivative liability representing the bondholders’ conversion feature (note 23) (net of issue costs) was estimated at $3,137,565 on 27 March 2006. The difference between the $60,000,000 principal amount due on maturity and the recorded liability component is accreted and recorded as finance costs using the effective interest method. The derivative financial instrument is recorded at fair value with resulting gains and losses recorded in finance income and costs. On 17 January 2007, the Corporation gave notice that it had exercised its option to redeem 550 outstanding bonds at 150% of par value for total proceeds of $82,500,000 plus accrued interest which was paid on 28 March 2007. This resulted in the recognition of a loss of $7,155,622 on the redemption, net of transaction costs, on the recorded liability and derivative liability. Previously, early in 2007, 50 bonds, with a total par value of $5,000,000, had been converted into 277,778 Common Shares. As a result of this conversion, a total amount of $7,104,327 was transferred to Share Capital from the convertible bonds and derivative liability of the convertible bonds.

203 2007 convertible bonds On 16 February 2007, the Corporation raised $165,000,000 by completing the private placement of convertible bonds. Issue costs amounted to $6,979,268 resulting in net proceeds of $158,020,732. The Corporation issued 1,650 unsecured convertible bonds at par, which have a maturity of five years and one day and an annual coupon of 8.00% payable semi-annually on 17 August and 17 February of each year. The bondholders had the right to convert the bonds into Common Shares at a price of $47.00 per share at any time. The Corporation had the right to redeem, in whole or part, the bonds for cash at any time on or before 16 February 2008, at 150% of par value. This right was not exercised. Proceeds were used to finance the redemption of the outstanding of convertible bonds, issued on 26 March 2006, at a premium of 150% and for general corporate funding purposes. Bondholders have a put option requiring the Corporation to redeem the bonds at par, plus accrued interest, in the event of a change of control of the Corporation or revocation or surrender of the Zapadno Chumpasskoye licence in Russia. In the event of a change of control and redemption of the bonds or exercise of the conversion rights, a cash payment of up to $19,700 on each bond will be made to the bondholder, the amount of which depends upon the date of redemption and market value at the date of any change of control event. The bonds included conversion features which in certain circumstances could be settled in cash and so these features represent a derivative financial instrument which is classified as a liability. The fair value of the liability component of the bonds (net of issue costs) was estimated at $140,154,215. The fair value of the derivative liability representing the bondholders’ conversion feature (note 23) (net of issue costs) was estimated at $17,866,517 on 16 February 2007. The difference between the $165,000,000 due on maturity and the initial liability component is accreted using the effective interest method and is recorded as finance costs. The derivative financial instrument is recorded at fair value with resulting gains and losses recorded in finance income and costs. In July 2007, a bondholder with US$7 million of bonds gave notice of the exercise of 70 bonds and received 148,937 Common Shares in August 2007. As a result of this conversion, $8,944,487 was transferred to Share Capital from convertible bonds, derivative liability component of convertible bonds and accrued liabilities. Pursuant to the terms of the convertible bond, the Corporation is required to provide security, in a separate escrow account, equal to the first three interest payments in the total amount of $19,841,551. The escrow account is reduced for each interest payment such that it will be nil on 17 August 2008. In August 2007, the first interest payment of $6,355,108 was made from the escrow account. Cash in the escrow account, including accrued interest income, is included in cash and cash equivalents.

Long-term debt In January 2005, a wholly-owned subsidiary of the Corporation received a sterling denominated loan of £4.5 million to refinance the acquisition of a corporate office. Interest on the loan is fixed at 6.515% for the first five years and is then variable at a rate of London Interbank Offered Rate (‘‘LIBOR’’) plus 1.35%. The loan, which is secured on the property, is scheduled to be repaid by 240 instalments of capital and interest at monthly intervals, subject to a residual debt at the end of the term of the loan of $3.5 million (£1,860,000). The current principal balance outstanding as at 30 September 2007 was $8,814,740 (31 December 2006—$8,557,513 (£4.4 million)).

Fair values At 31 December 2006 and 30 September 2007, the fair values of borrowings are approximately equal to their carrying amounts as the facilities bear interest at market rates of interest.

18 Provisions The Group’s asset retirement obligation results from net ownership interests in petroleum and natural gas assets including well sites and gathering systems. The Group estimates the total undiscounted inflation-adjusted amount of cash flows required to settle its asset retirement obligation to be approximately $406,835, which is expected to be incurred in 2012 and 2024. A cost pool specific discount rate, related to the liability, of 9% was used to calculate the fair value of the asset retirement obligation in 2007 (2006—10%).

204 A reconciliation of the asset retirement obligation is provided below:

31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Balance—Beginning of period ...... 328,553 434,849 434,849 62,322 Additions ...... — 62,322 — 62,372 Revision (in 2006 and 2007 due to change in discount rate) ...... 80,012 (41,170) (41,170) 3,204 Accretion expense (note 5) ...... 26,284 26,091 26,091 5,376 Liabilities transferred to discontinued operations (note 8) ...... — (419,770) (419,770) — 434,849 62,322 — 133,274

19 Share capital (a) Share capital The authorized share capital has unlimited number of Common Shares without par value.

31 December 2005 31 December 2006 30 September 2006 30 September 2007 Number Amount Number Amount Number Amount Number Amount $$$$ Balance—Beginning of period ...... 21,454,134 21,434,168 21,865,701 22,854,418 21,865,701 22,854,418 22,009,034 24,580,984 Issued on exercise of stock options (note 22) ...... 546,667 1,555,588 143,333 1,726,566 60,000 653,607 32,000 280,300 Normal course issuer bids (a) ...... (135,100) (135,338) —————— Issued on conversion of bonds (note 17) .——————426,715 16,048,814 Balance—End of period ...... 21,865,701 22,854,418 22,009,034 24,580,984 21,925,701 23,508,025 22,467,749 40,910,098

(a) Normal course issuer bids On 4 November 2004, the Corporation renewed its Normal Course Issuer Bid to acquire up to 1,069,506 Common Shares on the open market until 3 November 2005. This was replaced by a Normal Course Issuer Bid program that commenced on 4 November 2005 and expired on 3 November 2006 and was not renewed. Pursuant to the Normal Course Issuer Bid, the Corporation could have purchased up to 1,090,785 Common Shares. In 2005, the Corporation acquired 135,100 Common Shares at an average price of Cdn$7.85 per share for cancellation. No acquisitions under the Normal Course Issuer Bid were made in 2006.

205 20 Reserves and retained earnings (deficit) (a) Reserves 31 December 30 September 2005 2006 2006 2007 $$ $ $ (Unaudited) Available-for-sale investments revaluation reserve ...... — — — 168,000 Foreign currency translation reserve ...... — (4,003) — 133,768 — (4,003) — 301,768 Share-based payments reserve ...... 973,956 2,641,061 1,363,795 34,781,494 973,956 2,637,058 1,363,795 35,083,262

Movements Available-for-sale investments revaluation reserve Balance—Beginning of period ...... — — — — Revaluation ...... — — — 168,000 Balance—End of period ...... — — — 168,000

Foreign currency translation reserve Balance—Beginning of period ...... — — — (4,003) Currency translation differences arising during period ...... — (4,003) — 137,771 Balance—End of period ...... — (4,003) — 133,768 Share-based payments reserve Balance—Beginning of period ...... 24,421 973,956 973,956 2,641,061 Compensation costs—options issued ...... 1,082,112 2,074,727 441,253 32,365,616 Transfer to share capital on exercise of options ...... (132,577) (407,622) (51,414) (81,376) Options forfeited ...... — — — (143,807) Balance—End of period ...... 973,956 2,641,061 1,363,795 34,781,494

(b) Retained earnings (deficit) 31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Balance—Beginning of period ...... 52,879,284 43,876,180 43,876,180 15,508,425 Premium on repurchase and cancellation of Common Shares .... (740,879) — — — Net loss for the period ...... (8,262,225) (28,367,755) (12,517,910) (67,482,482) Balance—End of period ...... 43,876,180 15,508,425 31,358,270 (51,974,057)

(c) Nature and purpose of reserves i) Available-for-sale investments revaluation reserve Changes in the fair value and exchange differences arising on translation of available for sale investments such as equities, classified as available-for-sale financial assets, are taken to the available-for-sale investments revaluation reserve, as described in note 1(k). Amounts are recognised in profit and loss when the associated assets are sold or impaired. ii) Foreign currency translation reserve Exchange differences arising on retranslation of the foreign controlled entity are taken to the foreign currency translation reserve, as described in note 1(t). The reserve will be recognised in the income statement when the net investment is disposed. iii) Share-based payments reserve The share-based payments reserve is used to recognise the fair value of options issued, but not exercised, to employees.

206 21 Loss per share The following table summarizes the weighted average Common Shares used in calculating net earnings per share: Nine-month periods ended Year ended 31 December 30 September 2005 2006 2006 2007 (Unaudited) Weighted average Common Shares Basic ...... 21,650,215 21,917,363 21,895,628 22,317,412 Diluted ...... 21,860,371 22,095,507 22,045,516 23,284,968

The reconciling item between basic and diluted weighted average number of Common Shares is the dilutive effect of stock options and convertible bonds. A total of nil options (31 December 2005— 150,000; 31 December 2006—535,000; 30 September 2006—15,000) and 3,361,702 of shares relating to the convertible bonds (31 December 2005—nil; 31 December 2006—3,333,333; 30 September 2006— 3,333,333) were excluded from the above calculation, as they were anti-dilutive.

22 Share-based payments Stock options The Corporation has a stock option plan whereby certain directors, officers, employees and consultants of the Group may be granted options to purchase Common Shares. Under the terms of the plan, options granted normally vest one third immediately and one third in each of the years following the date granted and have a life of five years. Common Share options outstanding and exercisable:

31 December 2005 31 December 2006 Number Average Number Average of options exercise price of options exercise price (Cdn) $ (Cdn) $ Balance—Beginning of period ...... 476,667 1.31 425,000 9.57 Granted ...... 495,000 10.40 550,000 27.98 Exercised (note 19) ...... (546,667) 3.12 (143,333) 10.27 Balance—End of period ...... 425,000 9.57 831,667 21.63 Exercisable—End of period ...... 194,998 9.42 350,002 18.89

30 September 2006 30 September 2007 Number Average Number Average of options exercise price of options exercise price (Cdn) $ (Cdn) $ (Unaudited) Balance—Beginning of period ...... 425,000 9.57 831,667 21.63 Granted ...... 15,000 16.60 1,320,701 29.14 Exercised (note 19) ...... (60,000) 11.06 (32,000) 6.65 Forfeited ...... — — (41,667) 9.70 Balance—End of period ...... 380,000 9.61 2,078,701 26.87 Exercisable—End of period ...... 225,002 9.30 836,567 23.93

Number of options Remaining Exercise price (Cdn) Outstanding Exercisable life (years) $9.70 ...... 210,000 210,000 2.64 $16.60 ...... 15,000 10,000 3.73 $22.00—$29.14 ...... 1,853,701 616,567 4.20 2,078,701 836,567 4.04

207 During the nine-month period ended 30 September 2007, the weighted average share price at the date of option exercise was Cdn $41.97. (Cdn $18.36 during the nine-month period ended 30 September 2006). The fair value of each stock option grant on the date of grant was estimated using the Black-Scholes option-pricing model with the following weighted average assumptions and results. The fair value of stock options is amortised over the vesting period of the option.

31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Weighted average assumption and results Risk free interest rate (%) ...... 2.81 4.13 2.12 4.55 Volatility (%) ...... 58.86 42.99 62.40 45.00 Dividend yield (%) ...... — — — — Expected life (years) ...... 3.80 3.42 5.00 3.00 Grant date fair value (Cdn $) ...... 3.93 8.80 9.11 32.19

23 Derivative financial liability

31 December 30 September 2005 2006 2006 2007 $$$$ (Unaudited) Convertible bond — conversion option ...... — 27,997,140 8,621,068 32,810,103

For details of the convertible bond, refer to note 17. The fair value of the convertible bonds conversion option has been estimated using the Black-Scholes option-pricing model at each period end, with changes in the fair value of the conversion option recognised in income during the period. The expected life of the conversion option has been adjusted to reflect the bondholders’ put option and the Corporation’s redemption option as detailed in note 17.

24 Related party transactions During the nine-month period ended 30 September 2007, general and administrative expenses included an advisory fee of $806,607 (30 September 2006—$644,258) charged by Mr. Anthony Buckingham, a director of the Corporation who was appointed CEO on 6 October 2006. Mr. Atherton, a director of the Corporation, is also a director and CFO of Sea Dragon. The Group acquired 605,000 common shares of Sea Dragon on 9 March 2007 through the sale of its 65% interest in Pipelay and Naturalay Technologies. In 2006, general and administrative expenses included an advisory fee of $1,494,317 (2005—$877,686) charged by the same director. In 2005, the Corporation established a management and finance office in Switzerland that required this same director to relocate; he received a relocation allowance of $275,918.

208 25 Commitments and contingencies Heritage’s net share of outstanding contractual commitments at 30 September 2007 was estimated at:

Less than After Total 1 year 1-3 years 4-5 years 5 years $’000 $’000 $’000 $’000 $’000 Long-term debt ...... 17,662 617 1,234 8,334 7,477 Convertible bonds ...... 158,000 — — 158,000 — Total repayments of borrowings ...... 175,662 617 1,234 166,334 7,477 Operating leases ...... 9,642 229 458 458 8,497 Other long-term obligations ...... 140,000 40,000 100,000 — — Work program obligations ...... 124,759 58,236 52,259 14,065 200 Total contractual obligations ...... 274,401 98,465 152,717 14,523 8,697

The Corporation may have a potential residual obligation to satisfy any shortfall in officers’ and former officers’ secured real estate borrowings in the event of default, a shortfall on the proceeds from the disposal of the properties and the individuals being unable to repay the balance. The value of the residual obligation was estimated as insignificant. On 6 October 2006, the Corporation released Mr. Micael Gulbenkian from his role as its Chairman and Chief Executive Officer. In many of the countries in which the Group operates, land title systems are not developed to the extent found in many industrial countries and there may be no concept of registered title. Although the Group believes that it has 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 Production Sharing Contract (‘‘PSC’’) signed with the Kurdistan Regional Government (‘‘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 the KRI legal advice, the Directors believes that the PSC is valid and effective pursuant to the applicable laws. 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. 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. Furthermore, 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.

209 26 Non-cash investing and financing activities

Year ended Nine-month periods ended 31 December 30 September 2005 2006 2006 2007 $$ $ (Unaudited) Capitalised portion of stock-based compensation ...... — (940,000) — (8,957,752) Non-cash property, plant and equipment additions relating to the capitalised portion of stock-based compensation ...... — 940,000 — 8,957,752 Non-cash portion of sales proceeds on disposal of discontinued operations ...... — 719,380 — — Receipt of warrant as part of the sales proceeds from the disposal of discontinued operations ...... — (719,380) — — Disposition of subsidiaries (note 9) ...... — — — (1,342,868) Gain on disposal of subsidiaries (note 9) ...... — — — (1,077,132) Receipt of SeaDragon shares as a proceeds for disposal of subsidiaries (note 9) ...... — — — 2,420,000 Receipt of SeaDragon shares as a result of the issuance of the Corporation’s guarantee for a third party’s debt — — — 435,000 Accrual of payable representing the fair value of the Corporation’s guarantee issued for a third party’s debt — — — (435,000)

27 Subsequent events In October 2007, a wholly-owned subsidiary of the Corporation received a loan of U.S.$9,450,000 to refinance the corporate jet acquisition. Interest on the loan is variable at a rate of LIBOR plus 1.6 per cent. The loan, which is secured on the corporate jet, is scheduled to be repaid by 19 consecutive quarterly installments of principal. Each installment equals to $117,500 with the final installment being $7,217,500. The Corporation provided a corporate guarantee to the lender. In October 2007, a wholly-owned subsidiary of the Corporation executed a Production Sharing Contract with the Kurdistan Regional Government (KRG) over Miran Block in the southern region of the Kurdistan Region of Iraq. Heritage will also be operating as a 50/50 partner with the KRG to supply and operate a 20,000 barrel per day oil refinery in the vicinity of the licence area (‘‘Refinery Agreement’’). The Production Sharing Contract and Refinery Agreement include minimum work program and contractual commitments estimated at approximately $40 million and $140 million respectively, over four years. On 14 November, 2007, the Corporation closed an equity offering of 3,000,000 Common Shares which were issued at a price of Cdn $60.50 per Common Share for gross proceeds of Cdn $181.5 million to the Company. In addition, Albion Energy Limited sold 3,000,000 Common Shares at a price of Cdn $60.50 per Common Share for gross proceeds of Cdn $181.5 million. The ultimate owner of Albion Energy is Mr. Anthony Buckingham, a Director and Chief Executive Officer of the Corporation. In November 2007, a wholly-owned subsidiary of the Group was awarded a 60 per cent. participating interest in the Sanjawi Block in Zone II (Baluchistan), in 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. The Group has been appointed as an operator. The work programme shall be fully completed during initial three year term with financial commitment of $3.3 million in the first year, $0.4 million in the second year and $6.5 million in the third year. In December 2007, the Group executed a Production Sharing Contract with the Maltese Government for Areas 2 and 7 in the southeastern offshore region of Malta. Under the terms of the agreement, a wholly-owned subsidiary of the Group will serve as operator with a 100% interest. Areas 2 and 7 cover approximately 9,190 square km and 8,778 square km respectively. The total minimum contractual work programme has financial commitment of $22 million, distributed over the first three-year exploration phase, which can be extended for a further three years thereafter.

210 In November 2007, the Group farmed-in to two onshore exploration licenses in the Republic of Mali, in North-West Africa, with a gross area of over 72,000 square km. The Group was appointed as operator. Wholly owned subsidiaries of the Corporation have acquired a 75% working interest in Block 7 and Block 11. In return for earning the working interest the Corporation will fund all costs of the obligatory work programs for the next two years in both blocks, at a total estimated cost for the two licenses of between $15 million and $20 million. In February 2008, the Corporation announced that it will enter into a corporate reorganisation which will result in a newly incorporated company, Heritage Oil Limited (‘‘Heritage Jersey’’), becoming the parent company of the Corporation and its current subsidiaries. In connection with this reorganisation Heritage Jersey has agreed that, provided the reorganisation is completed, the 2007 Convertible Bonds outstanding at that date will be convertible with shares of Heritage Jersey rather than shares of the Corporation.

28 Explanation of transition to IFRS Reconciliation of equity reported under previous Canadian Generally Accepted Accounting Principles (CGAAP) to equity under International Financial Reporting Standards (IFRS):

At the date of transition IFRS—1 January 2005

Effect of Previous transition Notes CGAAP to IFRS IFRS $$$ Assets Non-current assets Intangible exploration assets ...... (b),(c) — 32,725,642 32,725,642 Intangible development costs ...... 1,013,012 — 1,013,012 Property, plant and equipment ...... (a),(b),(d),(g) 54,083,097 (32,306,191) 21,776,906 55,096,109 419,451 55,515,560

Liabilities Current liability Trade and other payables ...... 6,397,247 — 6,397,247

Non-current liability Provisions ...... 328,553 — 328,553 6,725,800 — 6,725,800 73,893,446 444,427 74,337,873

Equity Share capital ...... 21,434,168 — 21,434,168 Reserves ...... 24,421 — 24,421 Retained earnings ...... (a)(c)(d)(g) 52,434,857 444,427 52,879,284 73,893,446 444,427 74,337,873

211 At the end of the comparative period under previous CGAAP—31 December 2005

Effect of Previous transition Notes CGAAP to IFRS IFRS $$$ Assets Non-current assets Intangible exploration assets ...... (b),(c),(f) — 43,503,704 43,503,704 Intangible development costs ...... 1,187,371 — 1,187,371 Property, plant and equipment ...... (a),(b),(d),(g) 74,729,540 (49,446,988) 25,282,552 75,916,911 (5,943,284) 69,973,627

Liabilities Current liabilities Trade and other payables ...... 4,438,649 — 4,438,649 Borrowings ...... 248,045 — 248,045 4,686,694 — 4,686,694

212 Reconciliation of loss for the year ended 31 December 2005

Effect of Previous transition Notes CGAAP to IFRS IFRS $$ $ Revenue Petroleum and natural gas ...... 841,766 — 841,766 Drilling services ...... 342,359 — 342,359 1,184,125 — 1,184,125

Expenses Petroleum and natural gas ...... 465,110 — 465,110 Drilling rig operating ...... 196,804 — 196,804 General and administrative ...... (e) 5,249,649 456,747 5,706,396 Foreign exchange losses ...... 1,170,906 — 1,170,906 Depletion, depreciation and amortisation .... (c),(d),(g) 536,093 202,537 738,630 Exploration expenditure ...... (a) — 4,517,411 4,517,411 Impairment of unproved petroleum and natural gas interest ...... (a) 724,915 (724,915) — 8,343,477 4,451,780 12,795,257

Finance income (costs) Interest income ...... 330,290 — 330,290 Finance costs ...... (491,824) — (491,824) (161,534) — (161,534) Loss from continuing operations ...... (7,320,886) (4,451,780) (11,772,666) Earnings from discontinued operations ...... (g) 3,521,073 (10,632) 3,510,441 Net loss ...... (3,799,813) (4,462,412) (8,262,225)

213 Reconciliation of cash flow statement for the year ended 31 December 2005

Effect of Previous transition to Notes CGAAP IFRS IFRS $$$ Cash provided by (used in) Operating activities Net loss from continuing operations . . (a),(c),(d),(e),(g) (7,320,886) (4,451,780) (11,772,666) Items not involving cash Depletion, depreciation and amortisation ...... (c),(d),(g) 536,093 202,537 738,630 Finance costs — accretion expenses . — — — Foreign exchange losses ...... 480,253 — 480,253 Stock-based compensation ...... (e) 625,365 456,747 1,082,112 Impairment of unproved petroleum and natural gas properties ...... (a) 724,915 (724,915) — Increase in trade and other receivables ...... (258,398) — (258,398) Decrease in prepaid expenses ..... 1,921,678 — 1,921,678 Increase in inventory ...... (98,878) — (98,878) Increase in trade and other payables 52,946 — 52,946 (3,336,912) (4,517,411) (7,854,323) Discontinued operations ...... 4,034,035 — 4,034,035 697,123 (4,517,411) (3,820,288) Investing activities Property, plant and equipment expenditures ...... (a),(b) (16,289,772) 13,721,708 (2,568,064) Intangible exploration expenditures . . . (b) — (9,204,297) (9,204,297) Development expenditures ...... (174,359) — (174,359) (16,464,131) 4,517,411 (11,946,720) Discontinued operations ...... 279,782 — 279,782 (16,184,349) 4,517,411 (11,666,938) Financing activities Shares issued for cash ...... 1,423,011 — 1,423,011 Long-term debt ...... 8,577,350 — 8,577,350 Purchase of Common Shares for cancellation ...... (876,217) — (876,217) Repayment of long-term debt ...... (103,997) — (103,997) 9,020,147 — 9,020,147 Foreign exchange losses on cash held in foreign currency ...... (1,185,123) — (1,185,123)

Decrease in cash and cash equivalents (7,652,202) — (7,652,202) Cash and cash equivalents — Beginning of year ...... 16,235,523 — 16,235,523 Cash and cash equivalents — End of year ...... 8,583,321 — 8,583,321

214 At the end of the last reporting period under previous CGAAP—31 December 2006

Effect of Previous transition Notes CGAAP to IFRS IFRS $$$ Assets Non-current assets Intangible exploration assets (b)(c)(f)(k) — 54,767,332 54,767,332 Intangible development costs ...... 1,574,039 — 1,574,039 Property, plant and equipment ...... (a)(b)(d)(f)(g)(h)(k) 98,311,833 (66,124,735) 32,187,098 Deferred financing fees .... (i) 2,539,726 (2,539,726) — Other financial assets (j) 719,380 195,178 914,558 103,144,978 (13,701,951) 89,443,027

Current assets Inventories ...... (d)(g) 50,552 48,369 98,921 Prepaid expenses ...... 531,273 — 531,273 Trade and other receivables . 9,839,506 — 9,839,506 Cash and cash equivalents . . 46,861,146 — 46,861,146 57,282,477 48,369 57,330,846 160,427,455 (13,653,582) 146,773,873

Liabilities Current liabilities Trade and other payables . . 12,715,381 — 12,715,381 Borrowings ...... 147,720 — 147,720 12,863,101 — 12,863,101

Non-current liabilities Borrowings ...... (i) 65,525,524 (2,400,681) 63,124,843 Provisions ...... 62,322 — 62,322 Deferred tax liabilities ..... (f) 2,346,605 (2,346,605) — Derivative financial liability . (l) — 27,997,140 27,997,140 67,934,451 23,249,854 91,184,305 80,797,552 23,249,854 104,047,406 79,629,903 (36,903,436) 42,726,467

Equity Share capital ...... (i)(l) 27,865,874 (3,284,890) 24,580,984 Reserves ...... (e)(k) 2,533,532 103,526 2,637,058 Retained earnings (deficit) . (a)(c)(d)(e)(g)(h)(j)(k)(l) 49,230,497 (33,722,072) 15,508,425 79,629,903 (36,903,436) 42,726,467

215 Reconciliation of loss for the year ended 31 December 2006

Effect of Previous transition Notes CGAAP to IFRS IFRS $$$ Revenue Petroleum and natural gas ...... 3,938,512 — 3,938,512 Drilling services ...... 2,895,727 — 2,895,727 6,834,239 — 6,834,239

Expenses Petroleum and natural gas ...... 723,611 — 723,611 Drilling rig operating ...... 2,291,585 — 2,291,585 General and administrative ...... (e) 8,977,345 (349,218) 8,628,127 Foreign exchange losses (gains) ...... (k) 798,194 (171,189) 627,005 Depletion, depreciation and amortisation ..... (d)(g) 691,011 660,976 1,351,987 Exploration expenditure ...... (a) — 6,066,977 6,066,977 Impairment of unproved petroleum and natural gas ...... (a) 986,964 (986,964) — 14,468,710 5,220,582 19,689,292

Finance income (costs) Interest income ...... (h) 1,767,898 (431,547) 1,336,351 Finance costs ...... (h) (5,996,553) 1,354,427 (4,642,126) Loss on derivative liability ...... (i) — (24,851,295) (24,851,295) Unrealised gain on other financial assets ...... (j) — 195,178 195,178 (4,228,655) (23,733,237) (27,961,892) Loss from continuing operations ...... (11,863,126) (28,953,819) (40,816,945) Gain (loss) on disposal of discontinued operations ...... (g)(h) 9,950,968 (750,268) 9,200,700 Earnings from discontinued operations ...... 3,248,490 — 3,248,490 Net loss ...... (f) 1,336,332 (29,704,087) (28,367,755)

216 Reconciliation of cash flow statement for the year ended 31 December 2006 Effect of Previous transition Notes CGAAP to IFRS IFRS $$$ Cash provided by (used in) Operating activities Net loss from continuing operations ...... (a)(d)(e)(g)(h)(i)(k)(l) (11,863,126) (28,953,819) (40,816,945) Items not involving cash Depletion, depreciation and amortisation ...... (d)(g) 691,011 660,976 1,351,987 Finance costs—accretion expenses ...... (h) 860,895 (213,442) 647,453 Foreign exchange losses .... (k) 593,837 (171,189) 422,648 Stock-based compensation . . (e) 1,483,945 (66,901) 1,417,044 Impairment of unproved petroleum and natural gas properties ...... (a) 986,964 (986,964) — Gain on other financial assets (j) — (195,178) (195,178) Loss on derivative financial instruments ...... (l) — 24,851,295 24,851,295 Increase in trade and other receivables ...... (972,251) — (972,251) Increase in prepaid expenses . (312,051) — (312,051) Decrease in inventory ...... 142,809 — 142,809 Increase in trade and other payables ...... 725,738 — 725,738 (7,662,229) (5,075,222) (12,737,451) Discontinued operations ...... 3,748,853 — 3,748,853 (3,913,376) (5,075,222) (8,988,598)

Investing activities Property, plant and equipment expenditures ...... (a)(b)(h) (33,512,387) 21,247,324 (12,265,063) Intangible exploration expenditures ...... (a)(b)(h) — (16,172,102) (16,172,102) Intangible development expenditures ...... (386,668) — (386,668) (33,899,055) 5,075,222 (28,823,833) Discontinued operations ...... 17,576,116 — 17,576,116 (16,322,939) 5,075,222 (11,247,717)

Financing activities Shares issued for cash ...... 1,318,945 — 1,318,945 Convertible bonds ...... 60,000,000 — 60,000,000 Convertible bond issue costs . . . (3,000,000) — (3,000,000) Repayment of long-term debt . . (287,759) — (287,759) 58,031,186 — 58,031,186 Decrease in cash and cash equivalents ...... 37,794,871 — 37,794,871 Cash and cash equivalents— Beginning of year ...... 8,583,321 — 8,583,321 Foreign exchange gains on cash held in foreign currency .... 482,954 — 482,954 Cash and cash equivalents— End of year ...... 46,861,146 — 46,861,146

217 Notes to reconciliations a) Pre-licence costs Under Canadian GAAP all costs incurred prior to having obtained licence rights were included within property, plant and equipment. Under IFRS, such expenditures are expensed as incurred. The impact on adoption to IFRS at 1 January 2005 is a reduction in property, plant and equipment and retained earnings of $2,162,301. At 31 December 2005, this adjustment has resulted in a reduction in property, plant and equipment and retained earnings of $5,954,797, an increase in exploration expenditure for the year of $4,517,411, and a decrease in the impairment of unproved petroleum and natural gas interests recognised in the year of $724,915. The income tax impact was in a further reduction of property, plant, and equipment of $2,346,605 and a corresponding decrease in deferred tax liability. At 31 December 2006, this adjustment has resulted in a reduction in property, plant and equipment and retained earnings at $11,034,810, an increase in exploration expenditure for the year of $6,066,977, and a decrease in the impairment of unproved petroleum and natural gas interests recognised in the year of $986,964. b) Reclassification of exploration and evaluation costs Under Canadian GAAP property, plant and equipment included certain exploration and evaluation expenditure incurred within established geographic cost pools. Under IFRS, such exploration and evaluation costs are recognised as tangible or intangible based on their nature. At 31 December 2006, this has resulted in the reclassification from property, plant and equipment to intangible exploration assets of $56,311,426 (1 January 2005—$32,589,744; 31 December 2005—$45,111,919). c) Capitalisation of property, plant and equipment depreciation of intangible assets Under IFRS, depreciation of property, plant and equipment utilised in exploration activities is capitalised as intangible exploration assets. As these assets were classified as property, plant and equipment under Canadian GAAP, depreciation of fixed assets was not included in the balance. The impact on adoption to IFRS at 1 January 2005 is an increase in intangible exploration assets and retained earnings of $135,898. At 31 December 2005, an increase in intangible exploration assets and retained earnings of $171,728 and a decrease in depreciation expense for the year of $35,830. At 31 December 2006, an increase in intangible exploration assets and retained earnings of $171,728. d) Reversal of impairment Under IFRS, impairment losses previously recorded are reversed if the conditions giving rise to the impairment have reversed. The reversal of impairment losses was not permitted under Canadian GAAP. The impact on adoption to IFRS at 1 January 2005 is an increase in inventory of $24,976, an increase in property, plant and equipment of $1,656,846, and an increase in retained earnings of $1,681,822. At 31 December 2005, this has resulted in increases in inventory of $35,441, property, plant and equipment of $1,442,748, retained earnings of $1,478,189, and depletion expense for the year of $203,633. At 31 December 2006, this has resulted in increases in inventory of $26,638, property, plant and equipment of $1,071,212, retained earnings of $1,097,850 and depletion expense for the year of $380,339. e) Share-based payments Under Canadian GAAP, the Group recognised an expense related to their share-based payments on a straight-line basis through the date of full vesting. Under IFRS, the Group is required to recognise the expense over the individual vesting periods for the graded vesting awards. At 31 December 2005, this has resulted in increases in general and administrative expenses and share-based payments reserves of $456,747, with a corresponding decrease in retained earnings.

218 At 31 December 2006, this has resulted in increases in share-based payments reserves of $107,529, with a corresponding decrease in retained earnings. General and administrative expenses for the year decreased by $349,218. f) Deferred tax Under Canadian GAAP, the Corporation recognised a deferred tax liability and corresponding increase in property, plant and equipment associated with its acquisition of Russian properties. However, under IFRS deferred tax is only recognised on the initial recognition of an asset if it is acquired through a business combination. At 31 December 2005 and 31 December 2006, this has resulted in a reduction of property, plant and equipment and deferred tax liability of $2,346,605. There was no impact at 1 January, 2005. g) Depletion policy Upon transition to IFRS, the Corporation adopted a policy of depleting petroleum and natural gas interests on a units of production basis over proved plus probable reserves. The depletion policy under Canadian GAAP was units of production over proved reserves. The impact on adoption to IFRS at 1 January, 2005 is an increase in property, plant and equipment and retained earnings of $789,008. At 31 December 2005, this resulted in increases in property, plant and equipment and retained earnings of $743,642, and depletion expense for the year of $34,734, and a decrease in earnings from discontinued operations of $10,632. At 31 December, 2006, this resulted in decreases in property plant and equipment of $233,631, retained earnings of $211,900, and earnings from discontinued operations of $674,905, and increases in inventory of $21,731, and depletion expense for the year of $280,637. h) Capitalisation of borrowing costs Under Canadian GAAP all borrowing costs were expensed as incurred. Under IFRS, the Corporation capitalises those borrowing costs incurred for the development of qualifying assets. There was no change as at 1 January, 2005. At 31 December, 2006, this has resulted in increases in property, plant and equipment and retained earnings of $847,517, and reductions in interest income of $431,547, finance costs of $1,354,427, and gain on disposal of discontinued operations of $75,363. i) Deferred financing fees Under IFRS, loans and receivables are recognised net of transaction costs, with interest expense recognised over the term of the loan using the effective interest method. Under Canadian GAAP prior to 1 January, 2007, the Corporation recognised these transaction costs as deferred financing fees in non-current assets and amortised them into income on a straight-line basis over the term of the loan. At 31 December, 2006, this has resulted in a decrease in deferred financing fees of $2,539,716, borrowings of $2,400,681, and derivative financial liability of $139,045. j) Held for trading financial assets IFRS requires held for trading financial assets to be measured at fair value with changes in the fair value to be recorded in income in the period. Under Canadian GAAP, these assets were held at cost. There was no change on adoption of IFRS at 1 January, 2005. At 31 December, 2006, this has resulted in increases in other financial assets, retained earnings and unrealised gain on other financial assets of $195,178. k) Foreign currency translation Under IFRS, amounts are initially recognised in a subsidiary’s functional currency (the currency of the primary economic environment in which it operates) and are translated into the functional currency of the group in accordance with note 1(t). The assessment of functional currency has resulted in transactions and balances for the Corporation’s Russian subsidiary to be initially recognised in Russian roubles. Under Canadian GAAP, these subsidiaries were considered to be integrated and were translated with only monetary assets and liabilities retranslated using period end rates.

219 At 31 December, 2006, this has resulted in increases in property, plant and equipment of $103,065, intangible exploration assets of $64,121, and retained earnings of $171,189, with decreases in foreign exchange losses of $171,189 and the foreign currency translation reserve of $4,003. l) Convertible bonds Under Canadian GAAP, the Corporation’s convertible bonds were initially recognised with an allocation between equity and liability components based on their relative fair values. IFRS requires the recognition of a liability and an embedded derivative liability representing the bond holder’s conversion option. The fair value of the derivative financial liability is subsequently measured at fair value at each period end with changes in fair value being recognised in income. At 31 December, 2006, this has resulted in increases in derivative financial liabilities of $27,997,140 and a loss on derivative financial liabilities of $24,851,951, and decreases in other contributed equity of $3,145,845, and retained earnings of $24,851,295.

220 AUDITED FINANCIAL STATEMENTS RELATING TO HOC PREPARED IN ACCORDANCE WITH CANADIAN GAAP Set out on the following pages are: a) a letter from KPMG LLP, Calgary, Canada, consenting to the inclusion in this document of their audit report dated 22 March 2006 (and with respect to note 13, 28 March 2006) relating to the consolidated financial statements of HOC for the two years ended and as at 31 December 2005; and b) the audit report of KPMG LLP, Calgary, Canada, relating to the consolidated financial statements of HOC for the two years ended and as at 31 December 2005; and c) the consolidated financial statements of HOC for the two years ended and as at 31 December 2005 prepared in accordance with Canadian GAAP letter of consent.

221 AUDITORS’ CONSENT

The Board of Directors of Heritage Oil Limited We have read the UK prospectus (‘‘the Prospectus’’) proposed to be filed by Heritage Oil Limited in accordance with the Prospectus Directive Regulation and the Prospectus Rules of the Financial Services Authority of the United Kingdom dated March 28, 2008 relating to the proposed admission to listing and trading of Heritage Oil Limited on the main market of the London Stock Exchange plc. We have complied with Canadian generally accepted standards for an auditor’s involvement with offering documents. We consent to the use in the above-mentioned Prospectus of our report to the shareholders of Heritage Oil Limited on the consolidated balance sheets of Heritage Oil Corporation as at December 31, 2005 and 2004 and the consolidated statements of earnings (loss) and retained earnings and cash flows for each of the years in the two-year period ended December 31, 2005. Our report is dated March 22, 2006 (except as to note 13 which is as of March 28, 2006).

(Signed) ‘‘KPMG LLP’’ Chartered Accountants Calgary, Canada March 28, 2008

222 AUDITORS’ REPORT TO THE SHAREHOLDERS We have audited the consolidated balance sheets of Heritage Oil Corporation as at December 31, 2005 and 2004 and the consolidated statements of earnings (loss) and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Corporation as at December 31, 2005 and 2004 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

8FEB200818093203

Chartered Accountants Calgary, Canada March 22, 2006, except note 13 which is as of March 27, 2006

223 HERITAGE OIL CORPORATION CONSOLIDATED BALANCE SHEETS December 31, 2005 and 2004 (U.S. dollars)

2005 2004 $$ ASSETS CURRENT ASSETS: Cash and cash equivalents ...... 8,583,321 16,235,523 Accounts receivable ...... 1,318,450 4,640,802 Note receivable (note 7) ...... — 4,280,161 Inventories ...... 216,474 94,483 Prepaid expenses ...... 219,222 272,168 10,337,467 25,523,137 Property and equipment (note 3) ...... 72,382,935 54,083,097 Deferred development costs (note 4) ...... 1,187,371 1,013,012 83,907,773 80,619,246

LIABILITIES AND SHAREHOLDERS’ EQUITY CURRENT LIABILITIES: Accounts payable and accrued liabilities ...... 4,438,649 6,397,247 Current portion of long-term debt ...... 248,045 — 4,686,694 6,397,247 Long-term debt ...... 7,520,438 — Asset retirement obligations (note 5) ...... 434,849 328,553 SHAREHOLDERS’ EQUITY: Share capital and warrants (note 6 (b)) ...... 22,854,418 21,434,168 Contributed surplus (note 6 (g)) ...... 517,209 24,421 Retained earnings ...... 47,894,165 52,434,857 71,265,792 73,893,446 Commitments (note 12) Subsequent events (note 13) 83,907,773 80,619,246

See accompanying notes to consolidated financial statements.

On behalf of the Board:

MICAEL GULBENKIAN PAUL ATHERTON Director Director

224 HERITAGE OIL CORPORATION CONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGS Years ended December 31, 2005 and 2004 (U.S. dollars)

2005 2004 $$ REVENUE: Petroleum and natural gas ...... 6,286,702 5,592,721 Interest ...... 371,651 560,926 Other ...... 1,355,369 443,335 8,013,722 6,596,982 EXPENSES: Operating ...... 1,653,657 1,442,016 Royalties ...... 816,740 345,656 General and administrative ...... 5,249,862 2,633,667 Interest ...... 491,824 — Foreign exchange (gains) losses ...... 1,240,529 (1,488,026) Depletion, depreciation and accretion ...... 1,636,008 633,643 Write-down of unproved petroleum and natural gas interest (note 3) ...... 724,915 934,771 11,813,535 4,501,727 Earnings (loss) before the undernoted ...... (3,799,813) 2,095,255 Gain on sale of property and equipment (note 7) ...... — 26,269,113 Net earnings (loss) ...... (3,799,813) 28,364,368 Retained earnings, beginning of year ...... 52,434,857 24,028,812 Effect of change in accounting for: Asset retirement obligations (note 5) ...... — 55,558 Stock-based compensation (note 6 (g)) ...... — (13,881) Premium on purchase and cancellation of Common Shares (note 6 (e)) ..... (740,879) —

Retained earnings, end of year ...... 47,894,165 52,434,857 Net earnings (loss) per share (note 6 (f)): Basic ...... (0.18) 1.33 Diluted ...... (0.18) 1.31

See accompanying notes to consolidated financial statements.

225 HERITAGE OIL CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended December 31, 2005 and 2004 (U.S. dollars)

2005 2004 CASH PROVIDED BY (USED IN): OPERATING: Net earnings (loss) ...... $ (3,799,813) $ 28,364,368 Items not involving cash: Gain on sale of property and equipment (note 7) ...... — (26,269,113) Depletion, depreciation and accretion ...... 1,636,008 633,643 Foreign exchange (gains) losses ...... 480,253 (1,910,662) Stock-based compensation ...... 625,365 10,540 Write-down of unproved petroleum and natural gas interests (note 3) . . 724,915 934,771 Changes in non-cash operating working capital ...... 1,030,395 102,462 697,123 1,866,009 FINANCING: Shares issued for cash ...... 1,423,011 604,953 Long-term debt ...... 8,577,350 — Purchase of Common Shares for cancellation ...... (876,217) — Repayment of long-term debt ...... (103,997) — 9,020,147 604,953 INVESTING: Property and equipment expenditures ...... (20,554,465) (37,318,136) Proceeds on sale of property and equipment ...... — 16,400,000 Repayment of note receivable ...... 4,210,538 10,724,500 Development expenditure ...... (174,359) (210,957) Acquisition (note 4) ...... — (285) Changes in non-cash investing working capital ...... 333,937 (905,434) (16,184,349) (11,310,312) Foreign exchange gains (losses) on cash held in foreign currency ...... (1,185,123) 906,001 Decrease in cash and cash equivalents ...... (7,652,202) (7,933,349) Cash and cash equivalents, beginning of year ...... 16,235,523 24,168,872 Cash and cash equivalents, end of year ...... $ 8,583,321 $ 16,235,523 Supplementary information: Interest received ...... $ 397,640 $ 556,897 Interest paid ...... $ 491,824 —

See accompanying notes to consolidated financial statements.

226 HERITAGE OIL CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Years ended December 31, 2005 and 2004 (U.S. dollars) Heritage Oil Corporation (the ‘‘Corporation’’) is incorporated under the Business Corporations Act (Alberta) and its primary business activity is the exploration, development and production of petroleum and natural gas in the Middle East, Africa and Russia. The preparation of the consolidated financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from those estimates.

1. Significant accounting policies: (a) Basis of presentation: The consolidated financial statements include the accounts of the Corporation, its subsidiaries and its proportionate interests in corporate joint ventures. The majority of the Corporation’s business is transacted in U.S. dollars and, accordingly, the functional and reporting currency is U.S. dollars.

(b) Joint operations: Substantially all exploration, development and production activities are conducted jointly with others and accordingly, the Corporation only reflects its proportionate interest in such activities.

(c) Cash and cash equivalents: The Corporation considers deposits in banks, certificates of deposit and short-term investments with original maturities of three months or less as cash and cash equivalents.

(d) Inventories: Inventories consist of petroleum, condensate and liquid petroleum gas that are recorded at the lower of cost, at average cost basis, and net realizable value.

(e) Property and equipment: The Corporation follows the full cost method of accounting for petroleum and natural gas operations, whereby all costs related to the acquisition, exploration and development of petroleum and natural gas interests are accumulated within cost centres on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing interests, costs of drilling both productive and non-productive wells, major development projects and overhead charges directly relating to acquisition, exploration and development activities. Proceeds from the sale of petroleum and natural gas interests are applied against capitalized costs except for sales that would change the rate of depletion and depreciation by 20% or more, in which case a gain or loss is recorded. Capitalized costs, together with estimated future capital costs associated with proved reserves, are depleted and depreciated using the unit of production method based on estimated gross proved reserves of petroleum and natural gas as determined by independent engineers. For purposes of this calculation, reserves and production are converted to equivalent units of petroleum based on relative energy content of six thousand cubic feet of natural gas to one barrel of petroleum. Costs of acquiring and evaluating significant unproved petroleum and natural gas interests are excluded from costs subject to depletion and depreciation until it is determined that proved reserves are attributable to such interest or until impairment occurs.

227 The Corporation uses the full cost method of accounting for oil and gas activities. The method requires a detailed impairment calculation when events or circumstances indicate a potential impairment of the carrying amount of oil and gas assets may have occurred, but at least annually. An impairment loss is recognized when the carrying amount of a cost centre is not recoverable and exceeds its fair value. The carrying amount is assessed to be recoverable when the sum of the undiscounted cash flows expected from proved reserves plus the cost of unproved interests, net of impairments, exceeds the carrying amount of the cost centre. When the carrying amount is assessed not to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows from proved and probable reserves plus the cost of unproved interests, net of impairments, of the cost centre. The cash flows are estimated using expected future product prices and costs and are discounted using a risk-free interest rate. Drilling rig equipment is depreciated using the unit-of-production method based on 2,740 drilling days with a 20% salvage value. Corporate capital assets are amortized on a straight-line basis over their estimated useful lives. The building is amortized on a straight-line basic over 40 years.

(f) Asset retirement obligations: The Corporation records the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset and depleted and depreciated using a unit of production method over estimated gross proved reserves. Subsequent to the initial measurement of the asset retirement obligations, the obligations are adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

(g) Deferred development costs: Development costs related to specific projects that in the Corporation’s view have a clearly defined future market are deferred and amortized on a straight line basis commencing in the year following that in which the new product development was completed. All other research and development costs are charged to earnings in the year incurred.

(h) Revenue recognition: Revenues from the sale of petroleum and natural gas are recorded when title passes to an external party.

(i) Income taxes: The Corporation uses the asset and liability method of accounting for income taxes. Under the asset and liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date of enactment or substantive enactment.

(j) Derivative financial instruments: The Corporation uses derivative financial instruments from time to time to hedge its exposure to commodity price fluctuations. The Corporation does not enter into derivative financial instruments for trading or speculative purposes. The derivative financial instruments are initiated within the guidelines of the Corporation’s risk management policy. This includes linking all derivatives to specific firm commitments or forecasted transactions. The Corporation believes the derivative financial instruments are

228 effective as hedges, both at inception and over the term of the instrument, as the term and notional amount do not exceed the Corporation’s firm commitment or forecasted transaction and the underlying basis of the instrument matches the Corporation’s exposure. The Corporation enters into hedges of its exposure to petroleum and natural gas commodity prices by entering into crude oil and natural gas swap contracts, options or collars when it is deemed appropriate. These derivative contracts, accounted for as hedges, are not recognized on the balance sheet. Realized gains and losses on these contracts are recognized in petroleum and natural gas revenue in the same period in which the revenues associated with the hedged transaction are recognized. Premiums paid or received are deferred and amortized to earnings over the term of the contract.

(k) Foreign currency translation: Monetary items denominated in foreign currencies are translated to U.S. dollars at exchange rates in effect at the balance sheet date and non-monetary items are translated at rates of exchange in effect when the assets were acquired or obligations incurred. Revenue and expenses are translated at rates in effect at the time of the transactions. Foreign exchange gains and losses are included in earnings.

(l) Stock based compensation plan: The Corporation has a stock-based compensation plan, which is described in note 6. The Corporation accounts for all stock-based payments granted on or after January 1, 2002, using the fair value based method. Under the fair value based method, stock-based payments are measured at the fair value of the consideration received, or the fair value of the equity instruments issued, or liabilities incurred, whichever is more reliably measurable. The fair value of stock-based payments to non-employees is periodically re-measured until counterparty performance is complete, and any change therein is recognized over the period and in the same manner as if the Corporation had paid cash instead of paying with or using equity instruments. The cost of stock-based payments to non-employees that are fully vested and non-forfeitable at the grant date is measured and recognized at that date. No compensation cost is recorded for all other stock-based employee awards granted prior to January 1, 2004. Consideration paid by employees on the exercise of stock options is recorded as share capital. The Corporation discloses the pro forma effect of accounting for these awards under the fair value based method.

(m) Per share amounts: Basic per share amounts are computed by dividing net earnings by the weighted average shares outstanding during the reporting period. Diluted per share amounts are computed similar to basic per share amounts except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised and that the proceeds from such exercises were used to acquire common shares at the average market price during the reporting period.

(n) Measurement uncertainty: The amounts recorded for depletion and depreciation of petroleum and natural gas interests and the provision for asset retirement obligation costs are based on estimates. The cost recovery ceiling test is based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in such estimates in future periods could be significant.

(o) Comparative figures: Certain prior year balances have been reclassified to conform to the current year’s presentation.

229 2. Changes in accounting policies: (a) Asset retirement obligations: Effective January 1, 2004, the Corporation adopted a new Canadian accounting standard for asset retirement obligations. This standard focuses on the recognition and measurement of liabilities related to legal obligations associated with the future retirement of property, plant and equipment. Under this standard, these obligations are initially measured at fair value determined as the estimated future costs discounted to the present value and subsequently adjusted for the accretion of the discount factor and any changes in the underlying cash flows. The asset retirement cost is capitalized to the related asset and amortized into earnings over time. The effect of adoption of the new standard on the financial statements is disclosed in note 5. Prior to January 1, 2004, an estimate of future abandonment and restoration costs was provided for using the unit of production method over estimated gross proved reserves.

(b) Full cost ceiling test: Effective January 1, 2004, the Corporation adopted a new Canadian guideline on the application of full cost accounting, described in note 1(e). The guideline modifies how impairment is tested. Prior to January 1, 2004, an impairment loss was recognized when the carrying amount of a cost centre exceeded its recoverable amount. The recoverable amount was the sum of the undiscounted cash flows expected from the production of proved reserves plus the lower of cost or market of unproved interests less estimated future costs for administration, financing and site restoration. The cash flows were estimated using period end prices and costs. Adoption of the new guideline had no effect on the Corporation’s financial statements.

(c) Stock-based compensation: Effective January 1, 2004, the Corporation retroactively adopted the revised Canadian accounting standard for stock-based compensation and other stock-based payments described in note 1(l), without restatement of prior periods. Prior to January 1, 2004, no compensation cost was recorded for stock options granted to employees and directors. The Corporation previously disclosed the pro forma effect of accounting for these awards under the fair value based method. The effect of adoption of the revised standard on the financial statements is disclosed in note 6(g).

3. Property and equipment:

2005 2004 $$ Petroleum and natural gas interests and equipment ...... 73,159,179 54,514,733 Drilling equipment ...... 2,693,618 2,055,006 Building ...... 11,984,701 11,984,701 Other ...... 931,289 297,692 88,768,787 68,852,132 Accumulated depletion and depreciation ...... (16,385,852) (14,769,035) 72,382,935 54,083,097

230 A ceiling test was undertaken at December 31, 2005 to determine whether there was an impairment to cost centres with proved reserves. In undertaking the ceiling test the following forecast prices were used:

West Bukha Bukha Bukha Bukha Russia Russia Year Brent Congo condensate Propane Butane Gas Export Domestic $/bbl $/bbl $/bbl $/tonne $/tonne $/MMBTU $/bbl $/bbl 2006 ...... 55.50 54.00 56.16 360.19 370.24 1.00 50.60 29.91 2007 ...... 53.50 52.05 54.12 349.59 358.44 1.00 48.78 28.81 2008 ...... 49.50 48.16 50.05 328.39 334.84 1.00 45.13 26.63 2009 ...... 46.50 45.24 46.99 312.49 317.14 1.00 42.39 24.99 2010 ...... 45.00 43.78 45.47 304.54 308.29 1.00 41.03 24.17 2011 ...... 43.50 42.32 43.94 296.59 299.44 1.00 39.66 23.35 2012 ...... 43.50 42.32 43.94 296.59 299.44 1.00 39.66 23.35 2013 ...... 44.51 43.30 44.96 301.89 305.34 1.00 40.58 23.84 2014+ ...... +2%pa +2%pa +2%pa +2%pa +2%pa 1.00 +2%pa +2%pa

At December 31, 2005, the below new cost centres were considered to be in the preproduction stage and all costs, net of revenues, were capitalized in property and equipment and excluded from costs subject to depletion and depreciation.

2005 2004 $$ Uganda ...... 26,991,887 21,342,651 Russia ...... — 871,950 Iraq ...... 2,785,419 836,452 Democratic Republic of Congo ...... 464,285 428,540 Kazakhstan ...... 938,370 — Pakistan ...... 416,504 25,359 31,596,465 23,504,952

Major uncertainties affect the recoverability of these costs as the recovery of the costs outlined above is dependent on the Corporation obtaining licenses, achieving commercial production or sale. At December 31, 2005, the cost of unproved petroleum and natural gas interests of $11,727,768 (2004—$11,247,096) for cost centres that are no longer in the preproduction stage have also been excluded from costs subject to depletion and depreciation. In 2005, the Corporation capitalized $1,332,363 (2004—$441,075) of general and administrative costs relating to exploration and development activities. Following the acquisition of a 95% interest in the West Chumpass development license in 2005, costs in the Russian preproduction cost centre have been transferred into costs subject to depletion and depreciation. Undeveloped lands are assessed quarterly to determine whether impairment has occurred. In the fourth quarter of 2005, the Corporation wrote-off all of the costs held in the Nigeria and Turkmenistan preproduction cost centres.

4. Natural Pipelay Worldwide Limited (‘‘NPWL’’) and Naturalay Technologies Limited (‘‘NTL’’): On July 23, 2003, the Corporation acquired a one-third interest in NPWL and NTL for a nominal cash consideration of $300 and a commitment to loan up to $500,000 for NPWL’s development of the Buoyant Drum Lay System (‘‘Pipelay System’’). At December 31, 2005, NPWL and NTL, corporate joint ventures, were proportionately consolidated in the Corporation’s financial statements as substantially all activities are conducted jointly with others. On September 24, 2004, the Corporation acquired an additional 31.7% interest in both entities for a nominal cash consideration of $285 and a commitment to loan up to an additional $170,000 for the Pipelay System. Accordingly, the Corporation commenced proportionately consolidating the entities effective September 24, 2004. As the Pipelay System development is not complete to date, NPWL has

231 no results of operations other than deferred development costs. At December 31, 2005, NTL had no assets, liabilities or operations.

Previous Net assets acquired before non controlling interest consolidation Acquired Total $$$ Working capital ...... 334,199 (330,708) 3,491 Deferred development costs ...... 265,803 531,608 797,411 Note payable from the Corporation, without interest ...... (500,002) — (500,002) Note payable from other Shareholders ...... (100,000) (200,000) (300,000) — 900 900 Non-controlling interest ...... — (315) (315) 585 585

Cash consideration Acquired Total $$ Initial 33.3% interest acquired in 2003 ...... 300 300 Incremental 31.7% interest acquired in 2004 ...... 285 285 585 585

At December 31, 2005, the Corporation had also directly incurred deferred development costs of $63,133. In 2005, NPWL incurred deferred development costs of $174,359.

5. Asset retirement obligations: The effect of the change in accounting policy as outlined in note 2(a) has been recorded retroactively with restatement of prior periods. The effect of the adoption on the balance sheet and statement of earnings is presented below as increases (decreases):

Balance sheet At December 31, 2003 $ Asset retirement cost, included in property and equipment ...... 119,074 Asset retirement obligations ...... 153,599 Accumulated future abandonment and site restoration liability ...... (90,083) Retained earnings ...... 55,558

The Corporation’s asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites and gathering systems. The Corporation estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations is approximately $695,050, which is expected to be incurred in 2010. A credit-adjusted risk-free rate of eight percent was used to calculate the fair value of the asset retirement obligations. A reconciliation of the asset retirement obligations is provided below:

2005 2004 $$ Balance, beginning of year ...... 328,553 153,599 Additions ...... — 82,138 Revision ...... 80,012 80,528 Accretion expense, included in depletion and depreciation ...... 26,284 12,288 Balance, end of year ...... 434,849 328,553

At December 31, 2005, estimated asset retirement obligation costs to be accreted over the remaining proved reserves were $255,202 (2004—$234,529).

232 6. Share capital: (a) Authorized: Unlimited number of Common Shares without par value

(b) Issued:

2005 2004 Number Amount Number Amount $$ Common Shares Balance, beginning of year ...... 21,454,134 21,434,168 20,991,800 20,788,253 Issued on exercise of stock options (c) . . . 546,667 1,423,011 442,334 561,463 Stock based compensation exercised (g) . . — 132,577 — — Issued on exercise of warrants (d) ...... — — 20,000 84,452 Normal course issuer bid (e) ...... (135,100) (135,338) — — Balance, end of year ...... 21,865,701 22,854,418 21,454,134 21,434,168 Warrants Balance, beginning of year ...... 40,962 Exercise of warrants ...... (40,962) Balance, end of year ...... — Share capital and warrants, end of year .. 21,865,701 22,854,418 21,454,134 21,434,168

(c) Stock options: The Corporation has a stock option plan whereby certain directors, officers, employees and consultants of the Corporation may be granted options to purchase common shares. Under the terms of the plan, options granted normally vest one third immediately and one third in each of the years following the date granted and have a life of five years. In 2005, 150,000 options were issued to non-employees at an average exercise price of Cdn$12.00 per share and a term of 12 months. The cost of stock-based payments to non-employees that are fully vested and non-forfeitable at the grant date is measured and recognized at that date. Common Share options outstanding and exercisable:

Number Average Number Average of options exercise price of options exercise price (Cdn $) (Cdn $) Balance, beginning of year ...... 476,667 1.31 919,001 1.49 Granted ...... 495,000 10.40 — — Exercised ...... (546,667) 3.12 (442,334) 1.69 Balance, end of year ...... 425,000 9.57 476,667 1.31 Share capital and warrants exercisable, end of year ...... 194,998 9.42 476,667 1.31

Number of options Remaining Exercise prices (Cdn $) Outstanding Exercisable Life (years) $1.35-$2.88 ...... 30,000 30,000 1.40 $9.70-$13.00 ...... 395,000 164,998 3.90 425,000 194,998 3.73

233 (d) Warrants: The following outstanding Common Share warrants were issued pursuant to various private placements or borrowing arrangements.

Number of Average Number of Average warrants exercise price warrants exercise price (Cdn $) (Cdn $) Balance, beginning of year ...... ——20,000 2.80 Granted ...... — — — — Exercised ...... — — (20,000) 2.80 Balance, end of year ...... ————

(e) Normal course issuer bids: On November 4, 2004, the Corporation renewed its normal course issuer bid to acquire up to 1,069,506 Common Shares on the open market until November 3, 2005. This was replaced by a normal course issuer bid programme that commenced on November 4, 2005 and is scheduled to expire on November 3, 2006. Pursuant to the Normal Course Issuer Bid, the Corporation may purchase up to 1,090,785 Common Shares. Pursuant to the normal course issuer bid that expired on November 3, 2005, the Corporation acquired 135,100 Common Shares at an average price of Cdn$7.85 per share for cancellation. No further acquisitions under the normal course issuer bid were made in 2005. No Common Shares were acquired in 2004.

(f) Per share amounts: The following table summarizes the weighted average common shares used in calculating net earnings per share:

Weighted average common shares 2005 2004 Basic ...... 21,650,215 21,247,565 Diluted ...... 21,860,371 21,661,554

The reconciling item between basic and diluted weighted average number of Common Shares is the dilutive effect of stock options and warrants. A total of 150,000 options (2004—nil) and nil warrants (2004—nil) were excluded from the above calculation, as they were anti-dilutive.

(g) Stock based compensation: The effect of the change in accounting policy as outlined in note 2(c) has been recorded retroactively without restatement of prior periods. At January 1, 2004, the effect of the change resulted in an increase to contributed surplus and an offsetting decrease to retained earnings of $13,881. A reconciliation of contributed surplus resulting from adoption is provided below:

2005 2004 $$ Balance, beginning of year ...... 24,421 — Adoption of change in accounting policy (note 2(c)) ...... — 13,881 Stock-based compensation expense ...... 625,365 10,540 Exercised ...... (132,577) — Balance, end of year ...... 517,209 24,421

The fair value of each stock option grant on the date of grant was estimated using the Black- Scholes option-pricing model with the following weighted average assumptions and results. The

234 fair value of stock options are amortized over the vesting period of the option. No stock options were granted in 2004.

2005 Assumptions: Risk free interest rate ...... 2.81% Volatility ...... 58.86% Dividend yield ...... — Expected life (in years) ...... 3.80 Resulting weighted average fair value (Cdn $) ...... $ 3.93

7. Gain on sale of property and equipment: On June 9, 2004, the Corporation sold a call option for proceeds of $1,200,000 entitling the purchaser to acquire the Corporation’s overriding royalty interest in certain petroleum and natural gas interests in the Republic of Congo for proceeds of $30,400,000 by July 30, 2004. An additional contingent consideration of up to A 8,300,000 (approximately $10,000,000) may be payable on the sale of all or a portion of the interest by the purchaser by December 31, 2005. Concurrent with the exercise of the option, the purchaser would be required to sell a 7% working interest in another petroleum and natural gas interest in the Republic of Congo to the Corporation for $7,000,000. On June 30, 2004, the purchaser exercised the option and the Corporation became entitled to a cash consideration of $9,400,000, net of the $7,000,000 to acquire the other interest, and a Euro-denominated note receivable equivalent to $14,000,000 due on December 31, 2005 bearing interest at Euribor plus 2.65% per annum. The net cash consideration of $9,400,000 was received in July 2004. On September 28, 2004 and December 1, 2004, the purchaser repaid early $4,000,000 and $6,724,500 respectively of the $14,000,000 note receivable. On March 17, 2005, the purchaser fully repaid the note receivable. The sale of the unproved interest would have changed the rate of depletion and depreciation for the Republic of Congo by more than 20%; accordingly, a gain of $26,269,113 has been recognized in earnings.

8. Income taxes: Heritage Oil Corporation is subject to income taxes in Canada. Substantially all of the Corporation’s operating activities in 2004 and 2005 were outside of Canada in jurisdictions where the statutory tax rate is nil, since the producing assets in Oman and the Republic of Congo are subject to production sharing agreements. In 2005, the Corporation acquired a 95% interest in the West Chumpass licence. The operations in Russia will be subject to income tax in Russia. The Corporation has available tax deductions of approximately $10,976 (2004—$92,633) and tax losses of approximately $3,944,517 (2004—$3,334,846), which expire from 2006 to 2012. A valuation allowance has been applied to fully offset the future benefit of the tax deductions and losses.

9. Financial instruments: (a) Fair value of financial assets and liabilities: At December 31, 2005, the fair values of financial assets and liabilities are approximately equal to their carrying amounts due to the short maturities.

(b) Credit concentration and risk: All of the Corporation’s production is derived from the Republic of Congo and Sultanate of Oman. In 2005 and 2004, the Corporation sold all of its production, at any point in time, in each country to a single customer for each commodity. Accordingly, substantially all of the Corporation’s accounts receivables from petroleum and natural gas sales were from three customers. Debtors of the Corporation are subject to internal credit review to minimize the risk of non-payment. The Corporation does not anticipate any default as it transacts with creditworthy counterparties.

235 (c) Foreign exchange risk: The Corporation is exposed to foreign exchange fluctuations as it holds working capital and long-term debt in foreign currencies. In addition, a portion of the operating activities are conducted in sterling and Swiss francs. There are no exchange rate contracts in place at, or subsequent to, December 31, 2005.

(d) Interest rate risk: The Corporation is exposed to interest rate risks.

10. Long-term debt: In January 2005, a wholly-owned subsidiary of the Corporation received a sterling denominated loan of $8.45 million (£4.5 million) to refinance the acquisition of a corporate office. Interest on the loan is fixed at 6.515% for the first five years and then is variable at a rate of London Interbank Offered Rate (‘‘LIBOR’’) plus 1.35%. The loan, which is secured on the property, is scheduled to be repaid by 240 installments of capital and interest at monthly intervals, subject to a residual debt at the end of the term of the loan of $3.5 million (£1,860,000).

11. Related party transaction: In 2005, general and administrative expenses included an advisory fee of $877,686 (2004—$429,208) charged by a director of the Corporation. The Corporation established a management and finance office in Switzerland that required this director to relocate and he received a relocation allowance of $275,918.

12. Commitments: Heritage’s net share of outstanding commitments at year-end 2005 are estimated at:

Less than Payments Due by Period Total 1 year 1-3 years 4-5 years After 5 years U.S.$m U.S.$m U.S.$m U.S.$m U.S.$m Long Term Debt ...... 7,768 248 246 246 7,028 Capital Lease Obligations ...... — — — — — Operating Leases ...... 2,659 217 434 434 1,574 Purchase Obligations ...... — — — — — Other Long Term Obligations ...... 875 588 287 — — Work Programme Obligations ...... 19,350 16,950 2,400 — — Total Contractual Obligations ...... 30,652 18,003 3,367 680 8,602

The Corporation may have a potential residual obligation to satisfy the shortfall in certain individuals’ secured real estate borrowings in the event of default, a shortfall on the proceeds from the disposal of the properties and the individuals being unable to repay the balance. In the unlikely event this was to occur the Corporation would look to recover any monies direct from the individual.

13. Subsequent events: On March 27, 2006, the Corporation issued a $60,000,000 unsecured convertible bond, with a coupon of 10% and a term of five years and one day. The bond is convertible into Common Shares at a price of U.$.$18.00 per share at any time during the term of the bond. The Corporation may redeem the bond in whole or part at any time during the first 12 months at 150% of par value. The Corporation has no redemption rights after the first twelve months. The proceeds of the bond can be employed for development of the West Chumpass field in Russia and for general corporate purposes.

236 C. PRO FORMA FINANCIAL INFORMATION FOR THE COMPANY

Accountant’s report on pro forma financial information for Heritage Oil Limited

KPMG LLP 8 Salisbury Square, London, EC4Y 8BB, United Kingdom

The Directors Heritage Oil Limited Ordnance House 31 Pier Road St. Helier Jersey JE4 8PW Channel Islands 28 March 2008 Dear Sirs

Heritage Oil Limited (the ‘‘Company’’) We report on the pro forma financial information (the ‘‘Pro forma financial information’’) set out in Part VII(c) of the prospectus that will be dated 28 March 2008, which has been prepared on the basis described in note 1, for illustrative purposes only, to provide information about how the fundraising in November 2007 might have affected the financial information presented on the basis of the accounting policies adopted by the Group in preparing the financial statements for the period ended 30 September 2007. This report is required by paragraph 20.2 of Annex I of the Prospectus Directive Regulation and is given for the purpose of complying with that paragraph and for no other purpose.

Responsibilities It is the responsibility of the directors of the Company to prepare the Pro forma financial information in accordance with paragraph 20.2 of Annex I of the Prospectus Directive Regulation. It is our responsibility to form an opinion, as required by paragraph 7 of Annex II of the Prospectus Directive Regulation, as to the proper compilation of the Pro forma financial information and to report that opinion to you. Save for any responsibility arising under Prospectus Rule 5.5.3R (2)(f) to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to its inclusion in the prospectus.

Basis of Opinion We conducted our work in accordance with the Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. The work that we performed for the purpose of making this report, which involved no independent examination of any of the underlying financial information, consisted primarily of comparing the unadjusted financial information with the source documents, considering the evidence supporting the adjustments and discussing the Pro forma financial information with the directors of the Company. We planned and performed our work so as to obtain the information and explanations we considered necessary in order to provide us with reasonable assurance that the Pro forma financial information has been properly compiled on the basis stated and that such basis is consistent with the accounting policies of the Company.

237 Our work has not been carried out in accordance with auditing or other standards and practices generally accepted in the United States of America or other jurisdictions and accordingly should not be relied upon as if it had been carried out in accordance with those standards and practices.

Opinion In our opinion: the Pro forma financial information has been properly compiled on the basis stated; and such basis is consistent with the accounting policies of the Company.

(Signed) ‘‘KPMG LLP’’ KPMG LLP 28 March 2008

238 PRO FORMA NET ASSET STATEMENT The following pro forma net asset statement of the Group as at 30 September 2007 is prepared for illustrative purposes only and, because of its nature, addresses a hypothetical situation and therefore does not represent the actual financial position of the Group. It is prepared to illustrate the effect on the consolidated balance sheet of the Group of a fund raising that the Group closed on 14 November 2007, as if the placing had taken place on 30 September 2007, and is based on the consolidated balance sheet of the Group as at 30 September 2007 which has been extracted without material adjustment from the financial information set out in Part VII ‘‘Financial Information’’. Equity fundraising adjustment Group 30 September 2007 (note 2) Pro forma $$$ (note 1) (note 2) Assets Intangible exploration assets ...... 85,746,870 — 85,746,870 Property, plant and equipment ...... 59,105,312 — 59,105,312 Other financial assets ...... 4,200,909 — 4,200,909 149,053,091 — 149,053,091 Current assets Inventories ...... 79,768 — 79,768 Prepaid expenses ...... 340,402 — 340,402 Trade and other receivables ...... 6,455,303 — 6,455,303 Cash and cash equivalents ...... 61,894,711 176,511,326 238,406,037 68,770,184 176,511,326 245,281,510 217,823,275 176,511,326 394,334,601 Liabilities Current liabilities Trade and other payables ...... 15,781,606 — 15,781,606 Borrowings ...... 160,224 — 160,224 15,941,830 — 15,941,830 Non Current Liabilities Borrowings ...... 144,918,765 — 144,918,765 Provisions ...... 133,274 — 133,274 Derivative Financial Liability ...... 32,810,103 — 32,810,103 177,862,142 — 177,862,142 193,803,972 — 193,803,972 24,019,303 176,511,326 200,530,629

Notes: (1) The consolidated balance sheet of the Group as at 30 September 2007 has been extracted without material adjustment from Part VII ‘‘Financial Information’’. (2) Net proceeds of the placing: Cdn$ $ Placing proceeds ...... 181,500,000 186,436,800 Placing expenses ...... (9,662,650) (9,925,474) Net proceeds of the Placing ...... 171,837,350 176,511,326

The gross placing proceeds of Cdn$181,500,000 ($186,436,800) are based on 3,000,000 Common Shares being issued by the Group pursuant to the placing each at a price of Cdn$60.50 ($62.15) per Common Share. The Group’s Common Shares have no par value. Offer expenses are the fees and expenses incurred in connection with the placing of Cdn$9,662,650 ($9,925,474) related principally to investment banking, legal and accounting fees. The exchange rate used was Cdn$1: $1.0272. (3) No account has been taken of any trading or other transactions since 30 September 2007.

Impact on Earnings The Directors believe that, had the equity financing occurred at the beginning of the last financial period, the consolidated income statement would have been affected. Additional finance income would have been generated from interest earned on increased cash deposits arising from any unutilised net offer proceeds.

239 PART VIII—ILLUSTRATIVE PROJECTIONS OF THE GROUP Basis of Preparation Set out below, for the purposes of illustration only, is a summary of the illustrative projected cash flows of the Group for the period from 1 October 2007 to 31 December 2010 (the ‘‘Illustrative Projections’’). The Illustrative Projections have been prepared by the Directors and should be read in conjunction with the assumptions and the description of the basis of preparation set out below. The Illustrative Projections have been prepared solely for the purpose of complying with the requirement in paragraph 133(b)(ii) of the Committee of European Securities Regulators’ recommendations for the consistent implementation of the European Commission’s Regulation on Prospectuses no 809/2004 (the ‘‘CESR recommendation’’) that this document includes particulars of estimated cash flow for either the two years following publication of this document or, if greater, the period until the end of the first full financial year in which extraction of mineral resources is expected to be conducted on a commercial scale and for no other reason. In the absence of this requirement in the CESR recommendation, the Directors would not have included the Illustrative Projections in this document. It is emphasised that the Illustrative Projections, which are unaudited, do not constitute any form of forecast, whether of cash, profit or otherwise. The Illustrative Projections relate to an extended future period and accordingly the estimates and assumptions underlying the projections are inherently highly uncertain and are based on events that have not taken place, and are subject to significant economic, competitive and other uncertainties and contingencies beyond the Company’s control. Further, given the nature of the Group’s business and industry which is subject to a number of significant risk factors, there can be no assurance that the projected cash flows can be realised and it is probable that the actual cash flows will be higher or lower, possibly materially, than those projected. The attention of prospective investors is drawn to the ‘‘Risk Factors’’ set out elsewhere in this document. Since the Illustrative Projections are based on assumptions and factors which may be affected by unforeseen events and relate to an extended future period, the actual results reported may not correspond to those shown in the Illustrative Projections and any differences may be material.

Illustrative Projections

15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 $ million $ million $ million Net cashflow (used by) from operating activities . . . (10) 5 21 Taxation ...... 0 0 0 Cashflows from (used by) financing activities ..... 186 (1) (1) Capital expenditure ...... 116 107 134 Movement in cash ...... 60 (103) (114) Opening cash balance ...... 62 122 19 Closing cash balance ...... 122 19 (95)

The Illustrative projections are not presented in statutory format. For the purposes of the above Illustrative Projections the Directors have assumed that the production profile and the operating and capital expenditure assumptions are based on the production profile and the operating and capital expenditure levels set out in the RPS report in Part III of this document. The following principal bases and assumptions have been used by the Directors in preparing the above Illustrative Projections.

240 Production assumptions Production during the projected period is only assumed to arise in respect of the Bukha and West Bukha fields in Oman, together with the Zapadno Chumpasskoye field in Russia. Production as set out below is consistent with the assumptions stated in the RPS Report in Part III of this document.

15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 Boepd Boepd Boepd Oman: Bukha ...... 126 — — West Bukha ...... 375 1,560 1,878 Russia: Zapadno Chumpasskoye ...... 1,110 2,198 4,275

Production is expected to commence from the West Bukha field in the third quarter of 2008 with sales commencing in the same period. It is assumed that production from the Bukha field will cease when West Bukha commences production. The Directors have assumed that all the production licences are and will remain valid over the period of the Illustrative Projections. No additional production is assumed to arise from projects and activities which form part of the Group’s long-term strategic plans and intentions, but which are not reflected in the report prepared by RPS in Part III of this document. Production has only been included from projects which have proved and probable reserves certified by RPS at 30 September 2007.

Price assumptions The assumed weighted average selling prices for future oil, gas, condensate and LPG sales, set out below, are in accordance with the base case assumptions underlying the report prepared by RPS in Part III of this document.

15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 Oman: Condensate, $/bbl ...... 84 85 87 LPG, $/tonn ...... 542 547 555 Gas, $/mcf ...... 1 1 1 Russia: Crude oil, $/bbl ...... 55 53 51

Cost assumptions An overview of the operating and capital expenditures has been given below. These expenditures have been estimated in accordance with the long-term strategic plans of the Group at the date of this document, as reflected in the report prepared by RPS in Part III of this document.

Operating costs

15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 $ million $ million $ million Oman: Bukha ...... 1.0 — — West Bukha ...... 0.3 0.9 1.1 Russia: Zapadno Chumpasskoye ...... 7.8 9.9 12.6

241 Capital expenditure

15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 $ million $ million $ million Oman — West Bukha ...... 15.8 — 12.5 Uganda ...... 18.5 3.8 3.8 Russia ...... 43.2 85.4 84.7 Pakistan ...... 1.0 1.0 1.0 KRI...... 27.0 8.0 0.5 Malta ...... 5.9 0.4 22.8 Mali...... 4.8 8.8 8.3 116.2 107.4 133.6

There will be no abandonment of decommissioning costs throughout the forecast period. Capital expenditure and operating costs will arise in accordance with the commercial terms of the PSCs and licences. No additional capital expenditure is assumed to arise in relation to projects and activities that the Group is considering undertaking, but which are not reflected in the report prepared by RPS in Part III of this document, save for other minimum exploration work programmes and commitments. Cash flows in respect of receivables arise one month following the month in which they are generated. Cash flows in respect of payables arise one month following the month in which they are generated.

Taxation Income tax has been estimated in accordance with the applicable tax regimes and taking into consideration available losses and allowances in which the Group operates.

Financing assumptions

15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 $ million $ million $ million Repayment of Begal loan ...... 0.6 0.5 0.5 Repayment of Coatbridge loan ...... 0.2 0.2 0.2 0.8 0.7 0.7

At a future date twelve months from the date of this document, the Group will be seeking additional equity and/or debt financing round(s) or could consider selling non-core assets during the period of the Illustrative Projections to finance the remainder of the operational expenditures required to bring the initiated oil and gas development exploration activities into full production and fund exploration programmes. For the purposes of the Illustrative Projections only, it is assumed to be equity finance. The extent to which debt might be raised at a future time is not included within the Illustrative Projections and would create additional interest and capital repayments for the Group.

242 Macroeconomic assumptions The Directors have assumed the following:

Foreign exchange rates There will be no material fluctuations in respect of foreign exchange rates. The following exchange rates have been adopted throughout the projected period: 15 months ending 12 months ending 12 months ending 31 December 2008 31 December 2009 31 December 2010 RR/US$ ...... 25 25 25 US$/£ ...... 1.9973 1.9973 1.9973 CHF/US$ ...... 1.20 1.20 1.20 Cdn$/US$ ...... 0.98 0.98 0.98

Inflation Annual inflation will be 2 per cent. for operating expenses and 20 per cent. for general and administrative expenses throughout the forecast period.

Interest LIBOR will be 3 per cent. throughout the forecast period.

Commercial terms The Directors have assumed that commercial terms, specifically those of the Group’s PSCs and licences, will continue to be in line with those outlined in Part I of this document.

Other assumptions The Directors have assumed: There will be no changes in applicable legislation, taxation, regulations, political or economic conditions which will materially affect the Group’s or the Group’s customers’ operations; There will be no interruptions to business which would have a material adverse effect on the Group or its operations and customers; and For the purpose of the Illustrative Projections, it has been assumed that the Group will not make any major acquisitions or disposals, although such acquisitions or disposals may in fact occur.

Risk factors The Illustrative Projections are subject to a variety of material risk factors that could cause the actual cash flows to differ materially from those projected. The most significant risk factors impacting these Illustrative Projections are as follows. Exploration and development expenditure and success rates; Factors associated with operating in developing countries, political and regulatory instability; Oil and gas sales volumes and prices; and Reliance on key employees. Additional risk factors are discussed in the ‘‘Risk Factors’’ section of this document. The above risk factors could materially adversely affect the cash flows to an extent that the Group may need, after 12 months from the date of this document, in certain circumstances to obtain further debt or equity financing.

243 Accountant’s report on the illustrative cash flow projections The following is the full text of a report on the Illustrative Projections of the Company from KPMG LLP as reporting accountants:

KPMG LLP 8 Salisbury Square, London, EC4Y 8BB, United Kingdom

The Directors Heritage Oil Limited Ordnance House 31 Pier Road St. Helier Jersey JE4 8PW Channel Islands 28 March 2008 Dear Sirs

Heritage Oil Limited We report on the illustrative cash flow projections of Heritage Oil Limited (‘‘the Company’’) and its subsidiaries (‘the Group’) for the two year period ending 31 December 2010 (the ‘‘Illustrative Projections’’). The Illustrative Projections, and the material assumptions upon which they are based, are set out on pages 240-243 of the prospectus (the ‘‘Prospectus’’) issued by the Company and will be dated 28 March 2008. The Illustrative Projections have been prepared by the directors of the Company, for illustrative purposes only, in order to show a possible outcome and they should be read in conjunction with the assumptions and basis of preparation accompanying them. The Illustrative Projections have been presented solely for the purposes of complying with the Committee of European Securities Regulators (‘‘CESR’’) recommendations for the consistent implementation of the European Commission’s Regulations on Prospectuses No.809/2004 (the ‘‘CESR recommendations’’), paragraph 133. This report is required by paragraph 133(b)(iii) of the CESR recommendations and is given for the purpose of complying with that paragraph and for no other purpose.

Responsibilities It is the responsibility of the directors of the Company to prepare the Illustrative Projections in accordance with the requirements of paragraph 133(b)(ii) of the CESR recommendations. It is our responsibility to form an opinion as required by paragraph 133(b)(iii) of the CESR recommendations, as to whether the Illustrative Projections have been stated after due care and enquiry and to report that opinion to you. Save for any responsibility imposed by law or regulation to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in connection with this report or our statement, required by and given solely for the purposes of complying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to its inclusion in the Prospectus.

Basis of preparation of the Illustrative Projections The Illustrative Projections have been prepared on the basis stated on page 240 of the Prospectus. The Illustrative Projections, which are unaudited, are intended to show a possible outcome based on stated assumptions. The length of the period covered by the Illustrative Projections, means that the outcome based on the assumptions should be treated with even more caution than would be the case for a forecast.

244 Accordingly, the Illustrative Projections do not constitute any form of forecast, whether of cash, profit or otherwise. The Illustrative Projections relate to an extended future period and accordingly the estimates and assumptions underlying the projections are inherently uncertain, based on events that have not taken place, and are subject to significant economic, competitive and other uncertainties and contingencies beyond the Group’s control. Further, given the nature of the Group’s business and industry which is subject to a number of significant risk factors, there can be no assurance that the projected cash flows can be realised. Since the Illustrative Projections relate to the future actual cash flows are likely to differ from those projected because events and circumstances frequently do not occur as expected and the difference may be material. Attention is drawn to the ‘‘Risk Factors’’ section of the Prospectus.

Basis of opinion We conducted our work in accordance with the Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom to the extent that such standards are applicable in respect of this work. Our work included discussing with the directors of the Company the processes undertaken by them in identifying the key matters, risks and assumptions affecting cash flows and in compiling the Illustrative Projections based upon the disclosed assumptions. The assumptions upon which the Illustrative Projections are based are solely the responsibility of the directors of the Company. We planned and performed our work so as to obtain the information and explanations we considered necessary in order to provide us with reasonable assurance that the Illustrative Projections have been stated by the Company after due care and enquiry. Since the Illustrative Projections and the assumptions on which they are based relate to the future and may therefore be affected by unforeseen events, we can express no opinion as to whether the outcome shown in the Illustrative Projections will correspond with actual results to be reported and the differences may be material. Our work has not been carried out in accordance with auditing or other standards and practices generally accepted in the United States of America or other jurisdictions and accordingly should not be relied upon as if it had been carried out in accordance with those standards and practices.

Opinion In our opinion the Illustrative Projections have been stated by the Company after due care and enquiry.

Declaration For the purposes of Prospectus Rule 5.5.3R(2)(f) we are responsible for this report as part of the prospectus and declare that we have taken all reasonable care to ensure that the information contained in this report is, to the best of our knowledge, in accordance with the facts and contains no omissions likely to affect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 of Annex 1 of the Prospectus Directive Regulation. Yours faithfully

(Signed) ‘‘KPMG LLP’’ KPMG LLP 28 March 2008

245 PART IX—CORPORATE REORGANISATION 1. GROUP CAPITAL RE-ORGANISATION Company Structure In anticipation of Admission, HOC has proposed a reorganisation which will be completed by way of the Plan of Arrangement shortly before Admission. Pursuant to the Plan of Arrangement, each holder of HOC Common Shares will exchange their shares for Ordinary Shares or Exchangeable Shares on a one-for-ten basis. Exchangeable Shares have certain special rights described below including the right to direct the Trustee as to how it should exercise a number (equal to the number of Exchangeable Shares held) of the votes attaching to the Special Voting Share issued by the Company for these purposes. The option to elect for Exchangeable Shares has been granted by the Company in order to allow Canadian holders of HOC Common Shares to participate in the future performance of the Company in a tax efficient manner by continuing to hold Canadian securities or interests. The Exchangeable Shares are to be admitted to listing on the TSX and the Official List and to trading on the LSE’s main market for listed securities. Immediately following Admission, there will be 4,431,120 Exchangeable Shares issued and outstanding in HOC. Additionally, pursuant to the Plan of Arrangement, there will be 24,545,340 options outstanding. Under the conditions of the HOC Bonds, HOC is required to take (or to procure that there is taken) all necessary action to ensure that immediately upon completion of the Plan of Arrangement, at its option, either (a) the Company is substituted under the bonds as principal debtor in place of HOC or becomes a guarantor under the bonds and, in either case, to make necessary consequential amendments such that the bonds may be converted into or exchanged for Ordinary Shares; or (b) such amendments are made to the bonds such that the bonds may be converted into or exchanged for Ordinary Shares. Accordingly, at or immediately prior to Admission the terms and conditions of the HOC Bonds will be amended such that the holders of the HOC Bonds will be entitled to convert their bonds into Ordinary Shares subject to the terms and conditions of such bonds. Upon completion of the Plan of Arrangement, DutchCo (being an indirect wholly owned subsidiary of the Company) will own 100 per cent. of the share capital of Alberta CallCo which will in turn own 100 per cent. of the HOC Common Shares. As a result, HOC will be controlled by the Company by virtue of its indirect 100 per cent. membership in DutchCo. The corporate structure immediately subsequent to completion of the Plan of Arrangement will be as follows.

Non-Residents and Non-Electing Canadian Residents Voting and Exchange Trust Ordinary Shares Special Voting Share The Company (Jersey)

Jersey Subco (Jersey)

DutchCo (Netherlands)

Alberta CallCo (Alberta) Electing Canadian Residents

HOC Common Shares Exchangeable HOC Shares (Alberta) 12MAR200802413099

246 Arrangement Agreement Pursuant to the Arrangement Agreement, Canadian resident holders of HOC Common Shares who elect to do so will receive ten Exchangeable Shares for each HOC Common Share held. Canadian resident holders of HOC Common Shares who do not elect to receive Exchangeable Shares will receive ten Ordinary Shares for each HOC Common Share held. Non-residents of Canada will receive ten Ordinary Shares for each HOC Common Share held. Holders of HOC Common Shares who dissent to the Plan of Arrangement will be entitled to receive cash proceeds equal to the fair market value of their HOC Common Shares. Finally, holders of HOC Options will receive ten Options for each HOC Option held, and the exercise prices of such options will be divided by a factor of ten and converted into pounds sterling of the United Kingdom. A special meeting of Heritage Securityholders was held on 20 March 2008 at which Heritage Securityholders entitled to vote in respect of the Plan of Arrangement passed a resolution approving the Plan of Arrangement which required the affirmative vote of 662⁄3 per cent. of votes cast by holders of HOC Common Shares as well as by Heritage Securityholders present in person or represented by proxy. Following receipt of the approval of Heritage Securityholders, HOC has received from the Court of Queen’s Bench (Alberta) a final order approving the Plan of Arrangement. The Plan of Arrangement will become effective upon the Effective Date. The obligation of the parties to complete the Plan of Arrangement is subject to a number of conditions, including, but not limited to, the regulatory approvals and not more than 3 per cent. of holders of HOC Common Shares dissenting to the Plan of Arrangement. The Arrangement Agreement may be terminated by the mutual written consent of the parties at any time prior to the Effective Date.

2. RIGHTS OF EXCHANGEABLE SHAREHOLDERS General Exchangeable Shareholders will have certain economic rights, and Voting Rights in the management of the Company, pursuant to the Support Agreement, the Exchangeable Share provisions and the Voting and Exchange Trust Agreement as more fully described below and in section 6.3 of Part X of this document. Under the Exchangeable Share provisions, so long as Exchangeable Shares are outstanding, the Company covenants to the fullest extent permitted by law not to declare or pay any dividend on the Ordinary Shares unless: (i) HOC shall simultaneously declare or pay, as the case may be, an equivalent dividend on the Exchangeable Shares; and (ii) HOC shall have sufficient money or other assets or authorised but unissued securities available to enable the due declaration and the due and punctual payment, in accordance with applicable law, of any such dividend on the Exchangeable Shares. In the case of a share dividend or a dividend declared in property on the Ordinary Shares (and in certain other circumstances), the Support Agreement provides that the Exchangeable Shareholders are entitled to receive the economic equivalent for each Exchangeable Share from HOC. In addition, under the Support Agreement the Company has agreed to ensure that HOC will be in a position to make all necessary payments in the event of the liquidation, dissolution or winding-up of HOC, the retraction of the Exchangeable Shares, or the redemption of the Exchangeable Shares. Further, the Company has agreed to ensure that Alberta CallCo will be in funds to make all necessary payments in the event it exercises its right to acquire any Exchangeable Shares where a holder of Exchangeable Shares has given a redemption notice to HOC and in certain other circumstances.

Exchange Rights Subject to certain conditions, each Exchangeable Shareholder has the right to exchange all or any of its Exchangeable Shares for Ordinary Shares on a one-to-one basis, upon written request of such Exchangeable Shareholder. Notwithstanding the foregoing, holders of the Exchangeable Shares who are persons or entities in the United States of America or are a ‘‘US Person’’ within the meaning of Regulation S of the Securities Act as amended may not exercise such exchange right.

247 The Exchangeable Share provisions also provide that on the date on which less than 10 per cent. of the actual number of Exchangeable Shares issued remain outstanding, HOC will be entitled to redeem all but not less than all of the remaining outstanding Exchangeable Shares. HOC will deliver to each holder of Exchangeable Shares one Ordinary Share for each Exchangeable Share redeemed, together with any declared and unpaid dividends on the redeemed shares. Rights of Alberta CallCo Holding in HOC Immediately subsequent to completion of the Plan of Arrangement, Alberta CallCo will hold directly 100 per cent. of the HOC Common Shares. Voting Rights The holders of Exchangeable Shares are entitled to Voting Rights and through the Special Voting Share held by the Trustee will have the right to direct the Trustee how to vote at general meetings of the Company (on the basis of one vote for every Exchangeable Share) but not at any class meeting of the holder of the Special Voting Share. In addition, where the Company, inter alia, seeks to issue additional Ordinary Shares, is subject to a takeover offer, or reorganises its share capital, the Company will seek to put the holders of Exchangeable Shares in a similar position to the holders of Ordinary Shares. The principal rights attaching to the Exchangeable Shares and the Voting Rights attaching to the Special Voting Share held by the Trustee for the benefit of holders of Exchangeable Shares are granted under the terms of the Articles, the Exchangeable Share provisions, the Voting and Exchange Trust Agreement and/or the Support Agreement. Dividends Under the Support Agreement, the Company agreed not to pay a cash dividend to holders of Ordinary Shares unless a cash dividend in the same amount has been declared on all the Exchangeable Shares. Should the Board decide to pay a share dividend or a dividend declared in property to holders of Ordinary Shares, each holder of Exchangeable Shares would be entitled to receive the economic equivalent of such dividend on their Exchangeable Shares from HOC. Liquidation, Dissolution and Winding-Up Upon liquidation, dissolution or winding-up of HOC or distribution of assets of HOC for the winding- up of its affairs, the holders of Exchangeable Shares will receive in preference to the other classes of shares in HOC, one Ordinary Share per Exchangeable Share held. After the payment of this amount, the holders of HOC Common Shares shall be entitled to receive, on a pari passu basis, any remaining property of HOC.

248 PART X—ADDITIONAL INFORMATION 1. RESPONSIBILITY 1.1 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 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.

2. INCORPORATION 2.1 The Company was incorporated on 6 February 2008 in Jersey under the Act, as a company limited by shares with the name Heritage Oil Limited and registered number 99922. The Company has no commercial name other than its registered name. 2.2 The liability of the shareholders of the Company is limited. 2.3 The Company’s registered office is at Ordnance House, 31 Pier Road, St. Helier, Jersey JE4 8PW, and has a place of business at 28-30 The Parade, St Helier, JE1 1BG. 2.4 The Company is the ultimate holding company of the Group, and upon Admission and assuming completion in full of the Plan of Arrangement, will own (via its indirectly wholly owned subsidiary, Alberta CallCo) 100 per cent. of the HOC Common Shares. 2.5 There is no limitation on the length of life of the Company. 2.6 The principal legislation under which the Company operates is the Act and the regulations thereunder.

3. SUBSIDIARIES 3.1 Upon Admission, the Company has the following significant subsidiary undertakings all of which are, save as described below, private limited companies, wholly owned, and incorporated in the jurisdictions specified below.

Ownership Jurisdiction of Name/Date of Incorporation Registered Office Interest Incorporation Heritage Oil Corporation #260 Petex Building 100 per cent. Alberta, Canada (incorporated on 600 - 6th Avenue SW 30 October 1996) Calgary, Alberta T2P 0S5 Heritage Oil & Gas Limited Suite E2, Union Court Building 100 per cent. Commonwealth of (incorporated on Elizabeth Avenue and Shirley the Bahamas 14 January 1992) Street, Nassau, Bahamas Eagle Energy (Oman) Limited Castle Hill, Victoria Road, 100 per cent. Isle of Man (incorporated on 22 July 1992) Douglas, Isle of Man, IM2 4RB Heritage Energy Middle East P.O.Box 693, Hamilton Estate, 100 per cent. Island of Nevis Limited (incorporated on Charlestown, Nevis 8 January 2007) Heritage DRC Limited P.O.Box 693, Hamilton Estate, 100 per cent. Island of Nevis (incorporated on Charlestown, Nevis 17 December 2002) Coatbridge Estates Limited Akara Building, 24 De Castro 100 per cent. British Virgin Islands (incorporated on Street, Wickhams Cay, Road 24 September 2004) Town, Tortola, British Virgin Islands. ChumpassNefteDobycha ul. Industrialnaya 36 ‘‘b’’, 95 per cent. Russian Federation (incorporated on ZPU 16, PO 1106, 12 January 2005) Nizhnevartovsk, Khanty- Mansiyskiy Avtonomny District— Yugra, Tyumen Region, 628616, Russia.

249 Ownership Jurisdiction of Name/Date of Incorporation Registered Office Interest Incorporation Neftyanaya Geologicheskaya ul. Samotlornaya 20, 99 per cent. Russian Federation Kompaniya (incorporated on Nizhnevartovsk, Khanty- 2 March 2004) Mansiyskiy Avtonomny District— Yugra, Tyumen Region, 628600. Heritage Mali Block 7 Limited P.O. Box 693, Hamilton Estate, 100 per cent. Island of Nevis (incorporated on Charlestown, Nevis 17 October 2007) Heritage Mali Block 11 Limited P.O. Box 693, Hamilton Estate, 50 per cent. Island of Nevis (incorporated on Charlestown, Nevis 17 October 2007) Heritage Oil International Malta Akara Building, 24 de Castro 100 per cent. British Virgin Islands Limited (incorporated on Street, Wickhams Cay, Road 22 November 2007) Town, Tortola, British Virgin Islands Begal Air Limited, (incorporated Castle Hill, Victoria Road, 100 per cent. Isle of Man 9 October 2006) Douglas, Isle of Man, IM2 4RB TISE-Heritage Neftegaz 1st Brestskaya St. 15, 50 per cent. Russia (incorporated 27 June 2007) 125047 Moscow

4. SHARE CAPITAL 4.1 Share Capital of the Company

(a) As at the date of incorporation of the Company, the authorised and issued share capital of the Company was as follows:

Authorised Issued Number Amount Number Amount Unlimited number of No par value 1 Ordinary Share No par value Ordinary Shares

(b) The authorised share capital of the Company as at the date of this document is unlimited. The Company is authorised to issue shares with no par value designated as Ordinary Shares and a Special Voting Share. At the date of this document there are two Ordinary Shares in issue and one Special Voting Share in issue. (c) The authorised and issued fully paid up share capital of the Company as it is expected to be immediately following Admission is:

Authorised Issued Number Amount Number Amount Unlimited number of No par value 250,513,032 Ordinary Shares No par value Ordinary Shares 1 Special Voting No par value 1 Special Voting Share No par value Share

(d) Upon Admission, the Company will have 24,545,340 Options outstanding, and HOC will have 4,431,120 Exchangeable Shares outstanding, each of which will entitle the holder thereof to exchange each such Exchangeable Share or Option for one Ordinary Share, further details of which are set out in sections 1 and 2 of Part IX. (e) Save as disclosed in this document: (i) there are no acquisition rights and/or obligations over authorised but unissued share capital of the Company or HOC and neither the Company nor HOC has given any undertaking to increase its share capital;

250 (ii) no share or loan capital of the Company or HOC (or any of their subsidiaries) is under option or is the subject of an agreement, conditional or unconditional, to be put under option and there is no current intention to issue any of the authorised and unissued Ordinary Shares; (iii) there are no arrangements currently in force for involving the employees in the capital of the Company or HOC; and (iv) neither the Company nor HOC has any convertible securities, exchangeable securities or securities with warrants currently in issue. (f) The Company does not have in issue any shares not representing share capital. (g) No share capital of the Company is held by or on behalf of the Company or by any subsidiary of the Company. (h) None of the Directors nor members of their families has a related financial product referenced to the Ordinary Shares, other than Exchangeable Shares as disclosed in sections 1 and 2 of Part IX. (i) The ISIN (International Security Identification Number) to be used in relation to the Ordinary Shares in connection with Admission is JE00B2Q4TN56. (j) The legislation under which the Ordinary Shares have been created is the Act. (k) The Ordinary Shares are in registered form and, following Admission, will be capable of being held in uncertificated form, enabled through CREST. Further details of the operation of the CREST system are set out in Part I of this document. Definitive share certificates for offerees not settling through CREST are planned to be dispatched in the week commencing 7 April 2008. No temporary documents of title will be issued. Prior to the dispatch of such certificates, transfers will be certified against the Company’s register. (l) On 25 February 2008 and 18 March 2008, respectively, the existing shareholders of the Company at that date passed the following resolutions in respect of the Ordinary Shares: (i) Special resolution to change the status of the Company from a private company to a public company; and (ii) Special resolution to adopt the new Articles. (m) Save as summarised in this Part X, there are no restrictions on the free transferability of the Ordinary Shares. (n) Under articles 117 and 118 of the Act, an offeror in respect of a takeover offer which does not relate to shares of different classes, has the right to acquire shares to which the offer relates but which he has not acquired or contracted to acquire where he has acquired or is contracted to acquire not less than nine-tenths in number in the case of no par value companies of the shares to which the offer relates. The offeror may not issue a notice requiring the acquisition of minority shares unless he has acquired or contracted to acquire not less than nine-tenths in number of the shares to which the offer relates before the end of four months beginning with the date of the offer and no notice may be given after the end of the period of two months beginning with the date on which the offeror has acquired or contracted to acquire not less than nine-tenths in number. The squeeze out of minority shareholders can be completed at the end of 6 weeks from the date of the notice requiring the squeeze out. By virtue of article 119 of the Act, minority shareholders in respect of a takeover offer can require the offeror to acquire their shares provided the offeror has, before the end of the period within which the offer can be accepted, acquired or contracted to acquire not less than nine-tenths in number in the case of no par value companies of all the shares in the Company. Unless the offeror has given notice under article 117 of the Act, an offeror shall within one month of the end of the period within which the offer can be accepted give the remaining shareholders notice of their rights to require the offeror to acquire their shares. The notice may specify a period for the exercise of the remaining shareholders’ rights to be bought out, but that period must be at least 3 months after the end of the period during which the offer can be accepted. In a case in which a takeover offer relates to shares of different classes, the offeror has the right to acquire shares to which the offer relates but which he has not acquired or contracted to

251 acquire where he has acquired or is contracted to acquire not less than nine-tenths in number of any class in the case of no par value companies of the shares to which the offer relates. The offeror may not issue a notice requiring the acquisition of minority shares unless he has acquired or contracted to acquire not less than nine-tenths in number of any class of the shares to which the offer relates before the end of four months beginning with the date of the offer and no notice may be given after the end of the period of two months beginning with the date on which the offeror has acquired or contracted to acquire not less than nine-tenths in number of any class. The squeeze out of minority shareholders can be completed at the end of 6 weeks from the date of the notice requiring the squeeze out. By virtue of article 119 of the Act, minority shareholders in respect of a takeover offer can require the offeror to acquire their shares provided the offeror has, before the end of the period within which the offer can be accepted, acquired or contracted to acquire not less than nine-tenths in number of any class in the case of no par value companies of all the shares in the Company. Unless the offeror has given notice under article 117 of the Act, an offeror shall within one month of the end of the period within which the offer can be accepted give the remaining shareholders notice of their rights to require the offeror to acquire their shares. The notice may specify a period for the exercise of the remaining shareholders’ rights to be bought out, but that period must be at least 3 months after the end of the period during which the offer can be accepted. (o) There have been no public takeover bids by third parties in respect of the Ordinary Shares since incorporation.

4.2 Share Capital of HOC (a) As at the date of Admission, the authorised and issued share capital of HOC will be as follows:

Authorised Issued Number Amount Number Amount Unlimited HOC Common No par value Nil HOC Common Shares No par value Shares Unlimited Exchangeable No par value 4,431,120 Exchangeable No par value Shares Shares

(c) The ISIN (International Security Identification Number) to be used in relation to the Exchangeable Shares in connection with Admission is CA 4269283053. (d) The legislation under which the Exchangeable Shares will be created is the ABCA. (e) The Exchangeable Shares will be in registered form and, following Admission, will be capable of being held in uncertificated form. The directors of HOC will make arrangements immediately after Admission for trades in the Exchangeable Shares to be settled through CREST via depository interests representing the Exchangeable Shares for those Shareholders who wish to hold their Exchangeable Shares in electronic form. Definitive share certificates for offerees not settling through CREST are planned to be dispatched in the week commencing 7 April 2008. No temporary documents of title will be issued. Prior to the dispatch of such certificates, transfers will be certified against HOC’s register. (f) The Exchangeable Shares will be denominated in Canadian Dollars. (g) On 20 March 2008, existing securityholders of HOC passed a resolution to approve the Plan of Arrangement providing for, in effect, the exchange of all the issued and outstanding HOC Common Shares for Ordinary Shares or Exchangeable Shares. (h) Save as summarised in this Part X, there are no restrictions on the free transferability of the Exchangeable Shares. (i) HOC exists under the laws of the Province of Alberta, Canada and accordingly, transactions in the Exchangeable Shares will not be subject to the provisions of the City Code. Instead, until such time that HOC ceases to be a ‘‘reporting issuer’’ (as defined under applicable securities laws), HOC will remain subject to applicable Canadian securities laws. In Canada, securities laws are generally a matter of provincial/territorial jurisdiction and as a result, takeover bids are governed by the securities legislation in each province or territory.

252 In Alberta, the principal jurisdiction in Canada in which HOC is a ‘‘reporting issuer’’ (as defined under the provincial securities law), when any person (‘‘an offeror’’), except pursuant to a formal bid, acquires beneficial ownership of, or the power to exercise control or discretion over, or securities convertible into, voting or equity securities or any class of a reporting issuer that, together with such offeror’s securities would constitute 10 per cent. or more of the outstanding securities of that class, the offeror must immediately issue and file a press release announcing the acquisition, and file a report of such acquisition with the applicable securities regulatory authorities within two business days thereafter. Certain institutional investors may elect an alternate reporting system. Once an offeror has filed such report, the offeror is required to issue further press releases and file further reports each time the offeror, or any person acting jointly or in concert with the offeror, acquires beneficial ownership of, or the power to exercise control or direction over, or securities convertible into, an additional 2 per cent. or more of the outstanding securities of the applicable class. In Alberta, a takeover bid is generally defined as an offer to acquire outstanding voting or equity securities of a class made to any holder in Alberta of securities subject to the offer to acquire, if the securities subject to the offer to acquire, together with securities held by the offeror and any person acting in concert with the offeror, constitute in aggregate 20 per cent. or more of the outstanding securities of that class of securities at the date of the offer to acquire. Subject to limited exemptions, a takeover bid must be made to all holders of securities of the class that is subject to the bid who are in Alberta and must allow such security holders 35 days to deposit securities pursuant to the bid. The offeror must deliver to the security holders a takeover bid circular which describes the terms of the takeover bid and the directors of the reporting issuer must deliver a directors’ circular within fifteen days of the date of the bid, making a recommendation to security holders to accept or reject the bid and the reasons for the recommendation or a statement that the directors are unable to make or are not making a recommendation and the reasons why. Generally, an offeror may not enter into a collateral agreement, understanding or commitment that has the effect of providing a security holder with consideration of greater value than that offered to other security holders of the same class. While individual provincial securities laws in Canada only regulate offers to residents of that province, the Canadian Securities Administrators have adopted a policy whereby they may issue a cease trade order against a company if a takeover bid is not made to all Canadian security holders. Shareholders not resident in Canada are advised that the provincial securities laws in Canada may not apply in foreign jurisdictions. Accordingly, the availability of a takeover bid to Shareholders residing outside of Canada will be dependent on whether such takeover bid may be made to such non-Canadian Shareholders pursuant to applicable legislation of the jurisdiction in which the non-Canadian shareholder resides and the actions of the acquiring company. Under Alberta corporate law, where an offeror has successfully acquired 90 per cent. of the shares of a company (exclusive of those previously held by the offeror), the offeror may, within four months after making the offer to acquire shares of the company, send written notice to any shareholder who did not accept the offer compelling them to sell their shares on the same terms as contained in the original offer, subject to the right of such shareholder to make application to court, in which case the court may set the price and terms of payment and make such other consequential orders and give such directions as it deems appropriate. (j) There have been no public takeover bids by third parties in respect of the Exchangeable Shares since HOC’s last financial year and the current financial year.

5. JERSEY 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. Salient differences include (without limitation) the following: (a) the Act does not confer statutory pre-emption rights on shareholders relating to new share issues. But the Articles do confer pre-emption rights on shareholders relating to new issues of Ordinary Shares; (b) the Act does not impose any requirement for the directors to obtain the sanction of the shareholders to issue and allot shares. But the Articles do impose restrictions on amounts that

253 may be allotted annually, such amounts being subject to approval by the shareholders in a general meeting; (c) the Act permits the incorporation of companies with no par value shares and the holding by a Company of shares that it has redeemed or purchased as treasury shares; (d) there is no restriction under the Act for the allotment of shares in public companies unless paid up to at least one quarter of nominal value and the whole of any premium paid on such shares; (e) there is no requirement under the Act for directors to convene an extraordinary general meeting of the company where the net assets of the company are half or less of its called-up share capital; (f) there is no requirement under the Act for a company to have a minimum authorised share capital; (g) the Act does not contain net asset restrictions on distributions made by public companies; (h) there is no concept of an extraordinary resolution under the Act and a special resolution is required to be passed by two-thirds of shareholders present (in person or by proxy) at the relevant meeting and this two-thirds threshold cannot be increased; (i) the circumstances in which the Act permits a Jersey company to indemnify its directors in respect of liabilities incurred by the directors in carrying out their duties are limited, albeit in a slightly different manner to English companies. In particular, there is no express right for a Jersey company to pre-fund a director’s defence costs; (j) the Act does not require the directors of a Jersey company to disclose to the company their beneficial ownership of any shares in the company (although they must disclose to the company the nature and extent of any direct or indirect interest in a transaction entered into or proposed to be entered into by the company or by any subsidiary of the company which, to a material extent, conflicts with, or may conflict with, the interests of the company and of which such director is aware). Similarly, the Act does not grant the directors of a Jersey company a statutory power to request information concerning the beneficial ownership of shares. But the Articles do confer on the Company power to investigate interests in Shares; (k) under the Act, shareholders holding not less than one-tenth of the total voting rights of the shareholders of a company who have the right to vote at the meeting requisitioned may requisition a meeting of shareholders; (l) contrary to the position under the Companies Act and the New Companies Act where directors must disclose any interest they may have in a contract to be entered into by the company or by a subsidiary of the company, the director of a Jersey company need only make a disclosure where his interest materially conflicts with that of the company and of which such director is aware. But the Articles do restrict the directors’ ability to vote or count in the quorum in relation to such contracts of arrangements; (m) the Act does not contain a provision which would require prior shareholder approval of transactions with directors of the company. But the Articles do require the shareholders to approve any loans, quasi-loans or credit transactions granted or guaranteed by the Company to any of the directors or their connected persons, so long as the aggregate nominal amount of such transactions exceeds £10,000 for loans and quasi-loans, or £15,000 for credit transactions, and so long as any loan enabling such a director to properly perform his duties as a director does not exceed an aggregate nominal amount of £50,000. There are further exceptions contained within the Articles; (n) the Act does not confer power on the shareholders to remove directors from office and any such power has to be expressly provided for in the articles of the Jersey company. The Articles do confer power on the shareholders to remove directors from office; (o) under the Act, at a meeting of shareholders, a poll may be demanded in respect of any question by: (i) not less than five shareholders having the right to vote on the question; or (ii) a shareholder or shareholders representing not less than one-tenth of the total voting rights of all shareholders having the right to vote on the question. The Articles also provide that a poll may be demanded by (i) a member or members holding a right to vote on which an aggregate

254 nominal amount has been paid up of not less than one-tenth of the total sum paid up on all shares conferring that right, or (ii) the holder of the Special Voting Share; (p) there is no requirement under the Act to post the results of a poll taken at general meetings of a company on the company’s website and no power is conferred upon the shareholders to require an independent report on a poll. The Articles do however confer these requirements and powers; (q) there is no requirement under the Act that annual accounts and reports and preliminary statements of listed companies be posted on a website, nor is there a requirement that shareholders’ concerns about an audit of the company’s annual accounts be published on the company’s website. The Articles do however include a requirement that the annual accounts and reports and preliminary statements of the Company be posted on the Company’s website; (r) there is no requirement under the Act that a director’s report contain a business review (which under the New Companies Act would need to contain information about environmental matters, employees, social and community issues and persons with whom the company has contractual or other arrangements which are essential to the business). The Articles do however require that a director’s report contains such a business review; (s) there are no provisions in the Act requiring the production of directors’ remuneration reports. The Articles do however require the production of a directors’ remuneration report; (t) there is no express power under the Act for directors to make provisions for the benefit of employees of the company in connection with the cessation or transfer of the undertaking of the company; (u) while under the Act the directors of a Jersey company are required to act honestly and in good faith with a view to the best interests of the company and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances, under the New Companies Act a director, while promoting the success of the company, is also required to have regard to the interests of the company’s employees, and to the need to foster business relationships with suppliers and customers and the impact of the company’s operations on the environment; and (v) under Jersey law, the two principal procedures for dissolving a Jersey company are winding-up and désastre. The concept of a winding up is broadly similar to that under English law, except that under Jersey law, a winding-up may only be commenced by the Jersey company and not by one of its creditors. If the company is solvent the winding up will be a summary winding-up. If the company is insolvent, the winding-up will be a creditors’ winding-up. A creditor wishing to dissolve a Jersey company would seek to have the company’s property declared en désastre under the Bankruptcy (Desastre)´ (Jersey) Law 1990, as amended. If the company’s property is declared en désastre, all of the powers and property of the company (belonging to or vested in the company at the date of the declaration and all powers in or over or in respect of such property exercisable by the company at the date of the declaration and whether situated in Jersey or elsewhere) are vested in the Viscount (an officer of the court). The role of the Viscount is similar to that of a liquidator. The Viscount’s principal duty is to distribute the assets of the company among the persons entitled to receive them in accordance with their respective claims as provided by the law, he is not under an obligation to call any creditors’ meetings although he may do so. This list is intended to be illustrative only and does not purport to be exhaustive or to constitute legal advice. Any Shareholders wishing to obtain further information regarding their rights as a shareholder under Jersey law should consult their Jersey legal advisers.

6. MEMORANDUM AND ARTICLES OF ASSOCIATION OF THE COMPANY/ ARTICLES OF HOC 6.1 Memorandum of Association of the Company

The Memorandum is available for inspection at the address specified in section 19 below. Under the Act, the capacity of a Jersey company is not limited by anything contained in its memorandum

255 or articles of association or by any act of its members. Accordingly, the Memorandum does not contain an objects clause.

6.2 Articles of the Company The Articles have been adopted and include provisions to the following effect: (a) Alteration of share capital The Company may by special resolution alter its share capital in any manner permitted by the Act. Subject to the provisions of the Act, the Company may by special resolution reduce its stated capital accounts or other undistributable reserve in any way. (b) Purchase of own shares Subject to the Act the Company may purchase any of its own shares of any class, including any redeemable shares, provided that if there are in issue any shares which are admitted to the Official List and which are convertible into equity share capital of the Company of the class proposed to be purchased, the Company may not purchase or enter into a contract under which it will or may purchase such shares unless either the terms of issue of the convertible shares include provisions permitting the Company to purchase its own shares or provide for adjustment of the conversion terms upon such a purchase or the purchase or contract is first approved by special resolution of the holders of such convertible shares. (c) Share rights Without prejudice to any special rights attached to any existing shares or class of shares, any share in the Company may be issued with such preferred, deferred or other special rights or restrictions as the Company may by special resolution determine. Subject to the Act the Company may issue or convert any existing non-redeemable shares on such terms and in such manner as may be determined by Special Resolution into shares which are, or at the option of the Company or the holder are liable, to be redeemed. (d) Derivative Claims Except in relation to acts or omissions authorised or ratified by the Company in general meetings, a member, acting in good faith and in order to promote the success of the Company, shall at all times be at liberty to issue derivative proceedings in the name of the Company in respect of a cause of action vested in the Company with a view to obtaining relief on behalf of the Company, provided such proceedings are only in respect of a cause of action arising from an actual or proposed act or omission involving negligence, default, breach of duty or breach of trust by any Director, and may at any stage apply to the Court for leave to continue or take over the conduct of proceedings issued by the Company or by another member by way of derivative action if the manner in which the Company or the other member commenced or continued the proceedings amounts to an abuse of process of Court, or if either of them failed to prosecute the claim diligently or it is in all the circumstances more appropriate for the member to continue the proceedings as a derivative action. (e) Allotment of securities and pre-emption rights Subject to the provisions of the Act and any resolution of the Company passed in a general meeting, all unissued shares are at the disposal of the Directors and they may allot, grant options over or otherwise dispose of them to persons at such times and on such terms as they think proper provided that, although the Act does not provide any statutory pre-emption rights, shares issued for cash by the Company must first be offered to existing shareholders. Shares may not be issued for a non-cash consideration unless that consideration has been independently valued. (f) Share certificates Every holder of shares in certificated form whose name is entered on the Company’s register of members is entitled without payment to a certificate in respect of such shares within one month after allotment or within five business days (in the case of a transfer of fully-paid shares) after the lodgement of the instrument of transfer or within two months of the lodgement of the

256 instrument of transfer (in the case of a transfer of partly-paid shares). In the case of joint holders, delivery of a certificate to one of the joint holders shall be sufficient delivery to all. (g) Forfeiture and lien The Directors may from time to time make calls upon the members in respect of any monies unpaid on their shares, subject to the terms of allotment of such shares. Each member shall (subject to being given at least 14 days’ notice in writing specifying the time or times and place of payment) pay to the Company the specified amount called on his shares. If a member fails to pay in full any call or instalment of a call on or before the due date for payment, the Directors may at any time thereafter serve a notice in writing to him requiring payment of such unpaid amount together with any interest accrued thereon and any expenses incurred by the Company by reason of such non-payment. Interest shall accrue on any sums which are unpaid from the day appointed for payment thereof to the time of actual payment at such rate as the Directors may determine (although this shall not exceed 15 per cent. per annum). The notice shall state that in the event of non-payment in accordance with the notice, the shares on which the call has been made will be liable to be forfeited. The Company shall have a first and paramount lien on every share (not being a fully-paid share) for all monies (whether presently payable or not) called or payable at a fixed time in respect of such share. The Directors may waive any lien which has arisen. The Company may sell, in such manner as the Directors think fit, any share on which the Company has a lien if any sum in respect of which the lien exists is presently payable and is not paid within 14 days after a notice of intention to sell the share in default of payment shall have been given to the holder of the share. (h) Variation of rights (i) Subject to the provisions of the Act, the special rights attached to the Ordinary Shares may be varied or abrogated either with the written consent of the holders of two-thirds of issued Ordinary Shares or the sanction of a special resolution passed at a separate meeting of the holders of the Ordinary Shares. (ii) The special rights attached to the Special Voting Share may, subject to the provisions of the Act, be varied or abrogated with the sanction of a resolution passed at a separate meeting of the holder of the Special Voting Share by a majority of not less than two-thirds of the aggregate number of voting rights attaching to the Special Voting Share on a poll and which are exercised at such meeting (but not otherwise) and may be so varied or abrogated either whilst the Company is a going concern or during or in contemplation of a winding-up. To every such meeting the provisions of the Articles relating to general meetings and to the proceedings thereat shall mutatis mutandis apply, except that the necessary quorum shall be one person at least holding or representing by proxy at least one-third of the aggregate number of votes attaching to the Special Voting Share on a poll (but so that at any adjourned meeting the holder of the Special Voting Share present in person or by proxy shall be a quorum) and that all resolutions put to the vote at any such meeting shall be decided on a poll. (i) Transfer of shares (i) Any member may transfer all or any of his certificated shares by an instrument of transfer in writing in any usual or common form or in any other form acceptable to the Directors. An instrument of transfer shall be signed by or on behalf of the transferor and, unless the share is fully paid, by or on behalf of the transferee. An instrument of transfer may be under hand only. (ii) All transfers of shares which are in uncertificated form shall, subject to the Regulations, be effected by means of the relevant system. (iii) The Directors may in their absolute discretion and without assigning any reason therefor refuse to register any transfer of certificated shares, which are not fully-paid shares, provided that the refusal does not prevent dealings in the shares of that class from taking place on an open and proper basis.

257 (iv) The Directors may also refuse to register the transfer of a certificated share unless the instrument of transfer: (A) is lodged at the registered office or at another place appointed by the Directors accompanied by the certificate for the share to which it relates and such other evidence as the Directors may reasonably require to show the right of the transferor to make the transfer; (B) is in respect of one class of share only; and (C) is in favour of not more than four persons. (v) If the Directors refuse to register a transfer of a share in certificated form, they shall send the transferee notice of the refusal within two months after the date on which the instrument of transfer was lodged with the Company. (vi) No fee shall be charged for the registration of any instrument of transfer or other document relating to or affecting the title to a share. (vii) The holder of the Special Voting Share may only transfer the Special Voting Share in accordance with terms of the Voting and Exchange Trust Agreement. (j) General meetings (i) All general meetings of the Company other than annual general meetings shall be called extraordinary general meetings. (ii) Except for the annual general meeting, the Directors shall convene and the Company shall hold general meetings as extraordinary general meetings in accordance with the Act. The Directors may call general meetings whenever they think fit. On the requisition of members pursuant to the provisions of the Act, the Directors shall promptly convene an extraordinary general meeting. (iii) An annual general meeting and an extraordinary general meeting called for the passing of a special resolution shall be called by at least 21 clear days’ written notice. All other extraordinary general meetings shall be called by at least 14 days’ written notice. Subject to the provisions of the Act, the provisions of the Articles and to any restrictions imposed on any shares, the notice shall be sent to all the members, to each of the directors and to the auditors. (iv) The notice shall specify the time and place of the meeting and the general nature of the business to be transacted at the meeting. (v) In the case of an annual general meeting, the notice shall specify the meeting as such. In the case of a meeting to pass a special resolution, the notice shall contain a statement to that effect. (vi) The Company may specify in the notice a time, which may not be more than 48 hours before the time fixed for the meeting, by which a person must be entered on the Company register in order to have the right to attend and vote at the meeting. (vii) Any resolution (other than a procedural resolution) put to the vote at the meeting shall be decided on a poll. Procedural resolutions shall be decided on a show of hands, unless a poll is demanded by: (A) the chairman of the meeting; (B) not less than five members present in person or by proxy and entitled to vote on the resolution; (C) a member or members present in person or by proxy and representing not less than one-tenth of the total voting rights of all the members having the right to vote on the resolution; (D) a member or members present in person or by proxy and holding shares in the Company conferring a right to vote at the meeting being shares on which an aggregate sum has been paid up equal to not less than one-tenth of the total sum paid

258 up on all the shares conferring that right or, the member who is the holder of the Special Voting Share, whether present or in person by proxy; or (E) the holder of the Special Voting Share, whether present in person or by proxy. (viii) A poll shall be taken in such manner as the chairman of the meeting may decide. (ix) The members may require the directors to obtain an independent report on any poll taken at a general meeting of the Company, and if required to do so the directors must appoint an independent assessor within one week of the request for the independent report. (x) A Director shall, notwithstanding that he is not a member, be entitled to attend and speak at any general meeting and at any separate meeting of the holders of any class of shares in the capital of the Company. (xi) The chairman may at any time, without the consent of the meeting, adjourn the meeting for the purpose of declaring the results of a poll. (k) Voting rights (i) Ordinary Shares Subject to any special rights or restrictions as to voting attached to Ordinary Shares, on a show of hands every member who is present in person or by proxy shall have one vote and on a poll every member who is present in person or by proxy shall have one vote for every Ordinary Share of which he is the holder. On a poll, a person entitled to more than one vote need not use all his votes or cast all the votes he uses in the same way. A member may appoint more than one proxy. No member shall be entitled to vote, unless the Directors otherwise determine, at any general meeting unless all monies presently payable by him in respect of shares in the Company have been paid. A shareholder which has been duly served with a notice (equivalent to a notice under section 793 of the New Companies Act) and which is in default for a period of 14 days in supplying the Company with the information requested shall not be entitled to attend or vote personally or by proxy at shareholders’ meetings. (ii) Special Voting Share (A) The holders of Exchangeable Shares are entitled to Voting Rights and through the Special Voting Share held by the trustee of the Voting and Exchange Trust by the Company, will have the right to receive notice of, speak and vote at general meetings of the Company (on the basis of one vote for every Exchangeable Share) on the same basis as if they had exchanged their Exchangeable Shares for Ordinary Shares, to be calculated in accordance with the Voting and Exchange Trust. In addition, where the Company, inter alia, seeks to issue additional Ordinary Shares, is subject to a takeover offer, or reorganises its share capital, the Company will seek to put the holders of Exchangeable Shares in a similar position to the holders of Ordinary Shares. (B) The holder of the Special Voting Share may appoint more than one proxy to attend any general meeting in respect of all or a particular number of the votes attached to the Special Voting Share, provided that: (i) each instrument appointing a proxy shall specify the number of votes attached to the Special Voting Share for which the relevant person is appointed his proxy; (ii) each such person shall act as proxy for the holder of the Special Voting Share for the number of votes specified in the instrument appointing the person as a proxy; (iii) the total number of such proxies shall not exceed the total number of votes the holder of the Special Voting Share would be entitled to exercise on a poll at such general meeting; and (iv) notwithstanding the number of proxies appointed by the holder of the Special Voting Share for any general meeting, the holder of the Special Voting Share shall be deemed to constitute one member at such general meeting.

259 (l) Directors (i) Appointment of Directors Unless otherwise determined by ordinary resolution, the number of Directors shall be not less than three nor more than twenty. Directors may be appointed by ordinary resolution or by the Board and the Company may by ordinary resolution from time to time vary the minimum number and/or the maximum number of Directors. The Directors may appoint any one or more of their body to be executive Directors and confer on them any powers exercisable by them as the Directors think fit. (ii) Age of Directors No age limit shall apply to Directors. (iii) No Share Qualification A Director shall not be required to hold any shares in the capital of the Company by way of qualification. (iv) Retirement of Directors by Rotation Except at the first annual general meeting, at every subsequent annual general meeting, one third of the Directors shall retire from office, or if their number is not a multiple of three, the number nearest to one third shall retire from office. (v) Remuneration of Directors The emoluments of any Director holding executive office for his services as such shall be determined by the Board, and may be of any description. The ordinary remuneration of the Directors who do not hold executive office for their services shall not exceed £1,500,000 per annum in aggregate, or such higher amount as may be determined by ordinary resolution (including amounts payable under any other provision of the Articles). Any Director who holds any executive office, serves on any committee of the Board and performs services outside the scope of the ordinary duties of a Director, may be paid such extra remuneration as the Board may determine. In addition to any remuneration to which the Directors are entitled under the Articles, they may be paid all reasonable expenses as they may incur in attending and returning from meetings of the Directors or of any committee of the Directors or shareholders meetings or otherwise in connection with the business of the Company. The Board may provide benefits, whether by the payment of gratuities or pensions or by other retirement, superannuation, death or disability benefits or otherwise, for any past or present Director, and for any member of his family or any person who is or was dependent on him. (vi) Directors Loans The Company may make a loan to a director or give a guarantee or provide security in connection with a loan made by any person to such director, provided that the transaction has been approved by an ordinary resolution of the members. Approval for such transactions is not required provided the aggregate nominal value of the transaction does not exceed £10,000 (loans) or £15,000 (credit transactions), or in circumstances where the Company has provided a director with funds of up to £50,000 to enable him to properly perform his duties as an officer of the Company. (vii) Permitted interests of Directors Subject to the provisions of the Statutes, and provided that he has disclosed to the Board the nature and extent of any direct or indirect interest which conflicts or may conflict to a material extent with the interests of the Company, a Director notwithstanding his office: (A) may be a party to, or otherwise interested in, any transaction or arrangement with the Company in which the Company is otherwise interested;

260 (B) may be a director or other officer of, or employed by, or a party to any contract, transaction or arrangement with, or otherwise interested in, any body corporate promoted by the Company or in which the Company is otherwise interested; (C) may hold any other office or place of profit under the Company (other than the office of auditor) in conjunction with his office of director and may (and any firm of which he is a partner, employee or member may) act in a professional capacity for the Company (other than as auditor) and may be remunerated therefore; and (D) shall not, by reason of his office, be accountable to the Company for any benefit which he derives from any such office or employment or from any such transaction or arrangement or from any interest in any such body corporate and no such transaction or arrangement shall be liable to be avoided on the ground of any such interest or benefit. (viii) Restrictions on voting A Director shall not vote on any resolution of the Board concerning a matter in which he has a direct or indirect interest which conflicts or may conflict to a material extent with the interests of the Company but these prohibitions shall not apply to: (A) the giving of a guarantee, security or indemnity in respect of money lent or obligations incurred by him or any other person at the request of, or for the benefit of, the Company or any of its subsidiary undertakings; (B) the giving of a guarantee, security or indemnity in respect of a debt or obligation of the Company or any of its subsidiary undertakings for which the Director has assumed responsibility (in whole or part and whether alone or jointly with others) under a guarantee or indemnity or by the giving of security; (C) a proposal concerning an offer of shares, debentures or other securities of or by the Company or any of its subsidiary undertakings for subscription or purchase, in which offer he is or may be entitled to participate as a holder of securities or in the underwriting or sub-underwriting of which he is to participate; (D) a contract, arrangement, transaction or proposal concerning any other body corporate in which he or any person connected with him is interested, directly or indirectly, and whether as an officer, shareholder, creditor or otherwise, if he and any persons connected with him do not to his knowledge hold an interest representing 1 per cent. or more of either any class of the equity share capital of such body corporate (or any other body corporate through which his interest is derived) or of the voting rights available to members of the relevant body corporate (any such interest being deemed for the purpose of this paragraph to be a material interest in all circumstances); (E) a proposal for the benefit of employees of the Company or of any of its subsidiary undertakings which does not award him any privilege or benefit not generally accorded to the employees to whom the arrangement relates; and (F) a proposal concerning: (a) any insurance which the Company is empowered to purchase or maintain for, or for the benefit of, any Directors or for persons who include Directors; or (b) indemnities in favour of the Directors; or (c) the funding of expenditure by one or more Directors on defending proceedings against him or them; or (d) doing anything to enable such Director or Directors to avoid incurring such expenditure. (ix) Borrowing Powers The Board may exercise all the powers of the Company to borrow money, to guarantee, to indemnify, to mortgage or charge its undertaking, property, assets (present and future) and uncalled capital, and to issue debentures and other securities whether outright or as collateral security for any debt, liability or obligation of the Company or of any third party. (x) Indemnity of Officers Subject to the provisions of the Act every Director shall be indemnified out of the assets of the Company against any liability incurred by him by reason of having been a Director.

261 (xi) Dividends and Other Distributions (A) No dividend may be announced or declared by the Company on any Ordinary Shares unless prior to such announcement or declaration the Company has received from the directors of HOC confirmation that HOC will announce or declare an equivalent dividend on each Exchangeable Share in the manner required. (B) No dividend of any form may be declared, announced or paid on or in respect of the Special Voting Share. (C) Subject to the provisions of the Act, the Directors may pay fixed and interim dividends if and in so far as in the opinion of the Directors the profits of the Company justify such payments. If the Directors act in good faith, they shall not incur any liability to the holders of any shares for any loss they may suffer by the lawful payment, on any other class of shares having rights ranking after or pari passu with those shares, of any such fixed or interim dividend. (D) the Company may, upon the recommendation of the Directors, by ordinary resolution, direct payment of a dividend in whole or in part in specie and the Directors shall give effect to such resolution. (E) Except as otherwise provided by the rights attaching to any class of shares or the terms of issue thereof, all dividends shall be apportioned and paid pro rata according to the amounts paid on the shares during any period or portions of the period in respect of which the dividend is paid. (F) No dividend or other monies payable in respect of a share shall bear interest against the Company. (G) The Directors may retain any dividend or monies payable in respect of a share on which the Company has a lien, and may apply the same in or towards satisfaction of the moneys payable to the Company in respect of that share. (H) The Directors may deduct from any dividend or other monies payable to a holder of shares on or in respect of such shares all sums of money (if any) presently payable by the holder to the Company on account of calls or otherwise in relation to such shares. (I) Any dividend unclaimed after a period of 10 years from the date on which such dividend was declared or became due for payment shall be forfeited and revert to the Company. (J) The Directors may, if authorised by an ordinary resolution of the Company, offer any holder of shares the right to elect to receive shares by way of scrip dividend instead of cash. (xii) Winding-Up Except as provided by the rights and restrictions attached to any class of shares, the holders of Ordinary Shares will be entitled to participate in any surplus assets in a winding up in proportion to their shareholdings. The Company may, with the sanction of a special resolution and any other sanction required by the Act, divide among the members in specie the whole or any part of the assets of the Company and may, for that purpose, value any assets and determine how the division shall be carried out as between the members or different classes of members. The holder of the Special Voting Share shall be entitled, subject to the payment to the holders of all other classes of shares, of the amount paid up or credited as paid up or otherwise payable on such share, to repayment of the amount paid upon the Special Voting Share but shall have no further right to participate in the assets of the Company. (m) Disclosure of Beneficial Interests Although the Act does not contain equivalent provisions to section 793 of the New Companies Act, the Articles provide broadly equivalent provisions and provide that if at any time any member, or any other person (as appropriate) has been served with a notice from the company

262 and is in default for a period of 14 days supplying to the Company the information thereby required, then: (A) in respect of the shares in relation to which the default occurred (the ‘‘default shares’’, which shall include any share issued after the date of the notice in respect of such shares) the member shall not (for so long as the default continues) nor shall any transferee to whom any of such shares are transferred (other than pursuant to an approved transfer) be entitled to vote either personally or by proxy at a shareholders’ meeting or to exercise any other right confirmed by membership in relation to shareholder meetings; and (B) the Board may, in its absolute discretion by notice in writing (a ‘‘direction notice’’) to such member direct that where the default shares represent 0.25 per cent. or more of the issued shares of the class in question, the direction notice may additionally direct that in respect of the default shares: (I) no payment shall be made by way of dividend and no share shall be allotted in lieu of payment of a dividend; and (II) subject to the Regulations in the case of shares in uncertificated form, no transfer of any default share shall be registered unless: 1. the transfer is an approved transfer; or 2. the member is not himself in default as regards supplying the information required and the transfer is of part only of the member’s holding and when presented for registration, is accompanied by a certificate from the member in a form satisfactory to the Board to the effect that after due and careful enquiry the member is satisfied that none of the shares the subject of the transfer is a default share. Any direction notice shall cease to have effect in relation to any shares transferred by such member in accordance with the provisions described in section 6.2 (k)(xiii)(B)(II) above. (n) Accounts Although the Act does not contain equivalent provisions of the New Companies Act on a range of matters, the Articles provide broadly equivalent provisions in relation to the publication of accounts, and require that: (i) the Company comply with Chapters 4 to 6 (inclusive) (Annual Accounts, Directors’ Report, and Quoted Companies: Directors’ remuneration report) of Part 15 of the New Companies Act, mutatis mutandis as if it were a company subject to such statute; (ii) the Company ensures its annual accounts and reports are prepared pursuant to the Articles, and are made available as soon as reasonably practicable on a website and remain so available until the annual accounts and reports for the Company’s next financial year are made so available; and (iii) the Company complies with Chapters 7 to 9 (inclusive) (Publication of Accounts and Report, Public Companies: Laying of Accounts and Reports before General Meeting, and Quoted Companies: Members’ Approval of Directors’ Remuneration Report) of Part 15 of the New Companies Act mutatis mutandis as if it were a company subject to such statute. (o) Communications to all beneficial holders of Shares Although the Act does not contain equivalent provisions of the New Companies Act on a range of matters, the Articles provide broadly equivalent provisions in relation to communications to beneficial holders of shares, namely that a member who holds shares on behalf of another person may nominate that person to enjoy information rights (being the right to receive a copy of all communications that the Company sends to its members generally, including accounts, reports and hard copy form documents provided in another form (provided an address has been supplied and the Company has been notified)). Failure to give effect to the rights conferred by the nomination does not affect the validity of anything done by or on behalf of the Company.

263 6.3 Terms and Conditions of Exchangeable Shares

The Articles of HOC have been adopted and include the following terms and conditions of the Exchangeable Shares. (a) Ranking of Exchangeable Shares The Exchangeable Shares shall be entitled to a preference over the HOC Shares and any other shares ranking junior to the Exchangeable Shares with respect to the payment of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of HOC, whether voluntary or involuntary, or any other distribution of the assets of HOC among its shareholders for the purpose of winding up its affairs. (b) Dividends A holder of an Exchangeable Share shall be entitled to receive and the HOC Board of Directors shall, subject to applicable law, on each Company Dividend Declaration Date, declare a dividend on each Exchangeable Share: (i) in the case of a cash dividend declared on the Ordinary Shares, in an amount in cash for each Exchangeable Share, at the election of HOC in United States currency or the Canadian Dollar Equivalent thereof on the HOC Dividend Declaration Date, in each case, corresponding to the cash dividend declared on each Ordinary Share; (ii) in the case of a stock dividend declared on the Ordinary Shares to be paid in Ordinary Shares in such number of Exchangeable Shares for each Exchangeable Share as is equal to the number of Ordinary Shares to be paid on each Ordinary Share; or (iii) in the case of a dividend declared on the Ordinary Shares in property other than cash or Ordinary Shares, in such type and amount of property for each Exchangeable Share as is the same as or economically equivalent to (to be determined by the HOC Board of Directors as contemplated by this Part X, section 6.3(b)) the type and amount of property declared as a dividend on each Ordinary Share. Such dividends shall be paid out of money, assets or property of HOC properly applicable to the payment of dividends, or out of authorized but unissued shares of HOC, as applicable. The holders of Exchangeable Shares shall not be entitled to any dividends other than or in excess of the dividends referred to in this Part X, section 6.3(b). Cheques of HOC payable at par at any branch of the bankers of HOC shall be issued in respect of any cash dividends contemplated by this Part X, section 6.3(b) and the sending of such a cheque to each holder of an Exchangeable Share shall satisfy the cash dividend represented thereby unless the cheque is not paid on presentation. Certificates registered in the name of the holder of Exchangeable Shares shall be issued or transferred in respect of any stock dividends contemplated by this Part X, section 6.3(b) and the sending of such a certificate to each holder of an Exchangeable Share shall satisfy the stock dividend represented thereby. Such other type and amount of property in respect of any dividends contemplated by this Part X, section 6.3(b) shall be issued, distributed or transferred by HOC in such manner as it shall determine and the issuance, distribution or transfer thereof by HOC to each holder of an Exchangeable Share shall satisfy the dividend represented thereby. Subject to applicable law, no holder of an Exchangeable Share shall be entitled to recover by action or other legal process against HOC any dividend that is represented by a cheque that has not been duly presented to HOC’s bankers for payment or that otherwise remains unclaimed for a period of six years from the date on which such dividend was payable. The record date for the determination of the holders of Exchangeable Shares entitled to receive payment of, and the payment date for, any dividend declared on the Exchangeable Shares under this Part X, section 6.3(b) shall be the same dates as the record date and payment date, respectively, for the corresponding dividend declared and paid on the Ordinary Shares. If on any payment date for any dividends declared on the Exchangeable Shares under this Part X, section 6.3(b) the dividends are not paid in full on all of the Exchangeable Shares then outstanding, any such dividends that remain unpaid shall be paid, subject to applicable law, on a subsequent date or dates determined by the HOC Board of Directors on which HOC shall

264 have sufficient moneys, assets or property properly applicable to the payment of such dividends. The HOC Board of Directors shall determine, in good faith and in its sole discretion, economic equivalence for the purposes of this Part X, section 6.3(b), and each such determination shall be conclusive and binding on HOC and its shareholders. In making each such determination, the following factors shall, without excluding other factors determined by the HOC Board of Directors to be relevant, be considered by the HOC Board of Directors: (i) in the case of any stock dividend or other distribution payable in Ordinary Shares the number of such shares issued as a result of such stock dividend in proportion to the number of Ordinary Shares previously outstanding; (ii) in the case of the issuance or distribution of any rights, options or warrants to subscribe for or purchase Ordinary Shares (or securities exchangeable for or convertible into or carrying rights to acquire Ordinary Shares), the relationship between the Canadian Dollar Equivalent of the exercise price of each such right or option and the Current Market Price of an Ordinary Share; (iii) in the case of the issuance or distribution of any other form of property (including without limitation any shares or securities of the Company of any class other than Ordinary Shares, any rights, options or warrants other than those referred to above, any evidences of indebtedness of the Company or any assets of the Company), the relationship between the fair market value (as determined by the HOC Board of Directors in the manner above contemplated) of such property to be issued or distributed with respect to each outstanding Ordinary Share and the Current Market Price of an Ordinary Share; (iv) in the case of any subdivision, redivision or change of the then outstanding Ordinary Shares into a greater number of Ordinary Shares or the reduction, combination, consolidation or change of the then outstanding Ordinary Shares into a lesser number of Ordinary Shares or any amalgamation, merger, reorganisation or other transaction affecting Ordinary Shares, the effect thereof upon the then outstanding Ordinary Shares; and (v) in all such cases, the general taxation consequences of the relevant event to holders of Exchangeable Shares to the extent that such consequences may differ from the taxation consequences to holders of Ordinary Shares as a result of differences between taxation laws of Canada and Jersey (except for any differing consequences arising as a result of differing marginal taxation rates and without regard to the individual circumstances of holders of Exchangeable Shares). (c) Certain Restrictions So long as any of the Exchangeable Shares are outstanding (other than Exchangeable Shares held by the Company and its Affiliates), HOC shall not at any time without, but may at any time with, the approval of the holders of the Exchangeable Shares given as specified in Part X, section 6.3(i) of these share provisions: (i) pay any dividends on the HOC Common Shares or any other shares ranking junior to the Exchangeable Shares, other than stock dividends payable in HOC Common Shares or any such other shares ranking junior to the Exchangeable Shares, as the case may be; (ii) redeem or purchase or make any capital distribution in respect of HOC Common Shares or any other shares ranking junior to the Exchangeable Shares; (iii) redeem or purchase any other shares of HOC ranking equally with the Exchangeable Shares with respect to the payment of dividends or on any liquidation or distribution; or (iv) issue any Exchangeable Shares or any other shares of HOC ranking equally with, or superior to, the Exchangeable Shares other than by way of stock dividends to the holders of such Exchangeable Shares. The restrictions in sections 6.3(c)(i), 6.3(c)(ii), 6.3(c)(iii) and 6.3(c)(iv) above shall not apply if all dividends on the outstanding Exchangeable Shares corresponding to dividends declared and

265 paid to date on the Ordinary Shares shall have been declared and paid on the Exchangeable Shares. (d) Distribution on Liquidation In the event of the liquidation, dissolution or winding-up of HOC or any other distribution of the assets of HOC among its shareholders for the purpose of winding up its affairs, a holder of Exchangeable Shares shall be entitled, subject to applicable law and to the exercise by CallCo of the Liquidation Call Right, to receive from the assets of HOC in respect of each Exchangeable Share held by such holder on the effective date (the ‘‘HOC Liquidation Date’’) of such liquidation, dissolution or winding-up, before any distribution of any part of the assets of HOC among the holders of the HOC Common Shares or any other shares ranking junior to the Exchangeable Shares, an amount per share equal to the Current Market Price of an Ordinary Share on the last Business Day prior to the HOC Liquidation Date, which shall be satisfied in full by HOC causing to be delivered to such holder one Ordinary Share, together with all declared and unpaid dividends on each such Exchangeable Share held by such holder on any dividend record date which occurred prior to the HOC Liquidation Date (the ‘‘HOC Liquidation Amount’’). On or promptly after the HOC Liquidation Date, and subject to the exercise by CallCo of the Liquidation Call Right, HOC shall cause to be delivered to the holders of the Exchangeable Shares the HOC Liquidation Amount for each such Exchangeable Share upon surrender of the Exchangeable Shares, together with such other documents and instruments as may be required to effect a transfer of Exchangeable Shares under the ABCA and the constating documents of HOC and such additional documents and instruments as the Transfer Agent may reasonably require, at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC by notice to the holders of the Exchangeable Shares. Payment of the total HOC Liquidation Amount for such Exchangeable Shares shall be made either, (i) by delivery to each holder, at the address of the holder recorded in the securities register of HOC for the Exchangeable Shares, or by holding for pick-up on the instructions of the holder at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC by notice to the holders of Exchangeable Shares, on behalf of HOC certificates representing Ordinary Shares (which shares shall be duly issued as fully paid and shall be free and clear of any lien, claim or encumbrances) and a cheque of HOC payable at par at any branch of the bankers of HOC in respect of the declared and unpaid dividends on the Exchangeable Shares of such holder (in each case less any amounts withheld on account of tax required to be deducted and withheld therefrom); and (ii) by arranging for the credit of Ordinary Shares (which shares shall be duly issued as fully paid and shall be free and clear of any lien, claim or encumbrances) to CREST accounts on behalf of each holder and by delivery to each holder a cheque of HOC payable at par at any branch of the bankers of HOC in respect of the declared and unpaid dividends on the Exchangeable Shares of such holder (in each case less any amounts withheld on account of tax required to be deducted and withheld therefrom). On and after the Heritage Liquidation Date, the holders of the Exchangeable Shares shall cease to be holders of such Exchangeable Shares and shall not be entitled to exercise any of the rights of holders in respect thereof, other than the right to receive their proportionate part of the total Heritage Liquidation Amount, unless payment of the total Heritage Liquidation Amount for such Exchangeable Shares shall not be made upon surrender of the Exchangeable Shares in accordance with the foregoing provisions, in which case the rights of the holders shall remain unaffected until the total Heritage Liquidation Amount has been paid in the manner hereinbefore provided. HOC shall have the right at any time after the Heritage Liquidation Date to deposit or cause to be deposited certificates representing the Ordinary Shares issuable in respect of, and an amount representing declared and unpaid dividends on, the Exchangeable Shares represented by certificates or beneficial interests that have not, at the HOC Liquidation Date, been surrendered by the holders thereof, in a custodial account with any chartered bank or trust company in Canada. Upon such deposit being made, the rights of the holders of Exchangeable Shares after such deposit shall be limited to receiving their proportionate part of the total HOC Liquidation Amount (in each case less any amounts withheld on account of tax required to be deducted and withheld therefrom) for such Exchangeable Shares so deposited,

266 against surrender of the Exchangeable Shares held by them, in accordance with the foregoing provisions. Upon such payment or deposit of the total HOC Liquidation Amount and subject to the relevant entries being made in the register of members of the Company, the holders of the Exchangeable Shares shall thereafter be considered and deemed for all purposes to be holders of the Ordinary Shares delivered to them or the custodian on their behalf. After HOC has satisfied its obligations to pay the holders of the Exchangeable Shares the HOC Liquidation Amount per Exchangeable Share pursuant to Part X, section 6.3(d) of these share provisions, such holders shall not be entitled to share in any further distribution of the assets of HOC. (e) Retraction of Exchangeable Shares by holder A holder of Exchangeable Shares shall be entitled at any time, subject to the exercise by CallCo of the CallCo Redemption Call Right and otherwise upon compliance with the provisions of this Part X, section 6.3(e), to require HOC to redeem any or all of the Exchangeable Shares registered in the name of such holder for an amount per share equal to the Current Market Price of an Ordinary Share on the last Business Day prior to the Retraction Date (the ‘‘Retraction Right’’), which shall be satisfied in full by HOC causing to be delivered to such holder one Ordinary Share for each Exchangeable Share presented and surrendered by the holder, together with, on the payment date therefor, the full amount of all declared and unpaid dividends on any such Exchangeable Share (the ‘‘Dividend Amount’’) held by such holder on any dividend record date which occurred prior to the Retraction Date (the ‘‘Retraction Price’’). To effect such retraction, the holder shall present and surrender at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC by notice to the holders of Exchangeable Shares the certificate or certificates representing the Exchangeable Shares which the holder desires to have HOC redeem, together with such other documents and instruments as may be required to effect a transfer of Exchangeable Shares under the ABCA and the constating documents of HOC and such additional documents and instruments as the Transfer Agent may reasonably require, and together with a duly executed statement (the ‘‘Retraction Request’’): (i) specifying that the holder desires to have all or any number specified therein of the Exchangeable Shares represented by such certificate or certificates (the ‘‘Retracted Shares’’) redeemed by HOC; (ii) stating the Business Day on which the holder desires to have HOC redeem the Retracted Shares (the ‘‘Retraction Date’’), provided that the Retraction Date shall be not less than 15 Business Days nor more than 20 Business Days after the date on which the Retraction Request is received by HOC and further provided that, in the event that no such Business Day is specified by the holder in the Retraction Request, the Retraction Date shall be deemed to be the 20th Business Day after the date on which the Retraction Request is received by HOC; and (iii) acknowledging the overriding right (the ‘‘CallCo Redemption Call Right’’) of CallCo to purchase all but not less than all the Retracted Shares directly from the holder and that the Retraction Request shall be deemed to be a revocable offer by the holder to sell the Retracted Shares to CallCo in accordance with the CallCo Redemption Call Right on the terms and conditions set out below, provided however, that (i) notwithstanding the foregoing, in the event of an a tender offer, share exchange offer, issuer bid, take-over bid or similar transaction with respect to the Ordinary Shares (an ‘‘Offer’’), HOC will use its commercially reasonable efforts, expeditiously and in good faith, to put in place procedures or cause the Transfer Agent to put in place procedures to ensure that, if holders of Exchangeable Shares are required to retract such Exchangeable Shares to participate in the Offer, that any such retraction shall be conditional upon and shall only be effective if the Ordinary Shares tendered or deposited under such Offer are taken up, and (ii) notwithstanding any other provision of these Exchangeable Share provisions, holders of Exchangeable Shares who are Persons in the United States or are a U.S. Person may not exercise the Retraction Right. Subject to the exercise by CallCo of the CallCo Redemption Call Right, upon receipt by HOC or the Transfer Agent in the manner as specified herein, of a certificate or certificates

267 representing the Retracted Shares, together with a Retraction Request, and provided that the Retraction Request is not revoked by the holder in the manner specified in this Part X, section 6.3(e), HOC shall redeem the Retracted Shares effective at the close of business on the Retraction Date and shall deliver or cause to be delivered to such holder certificates representing the Ordinary Shares to which such holder is entitled with respect to such shares, and on the designated payment date therefor, a cheque of HOC payable at par at any branch of the bankers of HOC in respect of any dividends on the Retracted Shares for which the record date was prior to the Retraction Date and the payment date was after the Retraction Date (in such case less any amounts withheld on account of tax required to be deducted and withheld therefrom). If only a part of the Exchangeable Shares represented by any certificate are redeemed (or purchased by CallCo pursuant to the CallCo Redemption Call Right), a new certificate for the balance of such Exchangeable Shares shall be issued to the holder at the expense of HOC. Upon receipt by HOC of a Retraction Request, HOC shall immediately notify CallCo thereof and shall provide CallCo with a copy of the Retraction Request. In order to exercise the CallCo Redemption Call Right, CallCo must notify HOC of its determination to do so (the ‘‘CallCo Call Notice’’) within five Business Days of notification to CallCo by HOC of the receipt by HOC of the Retraction Request. If CallCo does not so notify HOC within such five Business Day period, HOC will notify the holder as soon as possible thereafter that CallCo will not exercise the CallCo Redemption Call Right. If CallCo delivers the CallCo Call Notice within such five Business Day period, and provided that the Retraction Request is not revoked by the holder in the manner specified in this Part X, section 6.3(e), the Retraction Request shall thereupon be considered only to be an offer by the holder to sell the Retracted Shares to CallCo in accordance with the CallCo Redemption Call Right. In such event, HOC shall not redeem the Retracted Shares and CallCo shall purchase from such holder and such holder shall sell to CallCo on the Retraction Date the Retracted Shares for a purchase price per share equal to the Retraction Price per share (the ‘‘Purchase Price’’). To the extent that CallCo pays the Dividend Amount in respect of the Retracted Shares, HOC shall no longer be obligated to pay any declared and unpaid dividends on such Retracted Shares. Provided that CallCo has complied with this Part X, section 6.3(e), the closing of the purchase and sale of the Retracted Shares pursuant to the CallCo Redemption Call Right shall be deemed to have occurred as at the close of business on the Retraction Date and, for greater certainty, no redemption by HOC of such Retracted Shares shall take place on the Retraction Date. In the event that CallCo does not deliver a CallCo Call Notice within such five Business Day period, and provided that the Retraction Request is not revoked by the holder in the manner specified in Part X, section 6.3(e), HOC shall redeem the Retracted Shares on the Retraction Date and in the manner otherwise contemplated in this Part X, section 6.3(e). Notwithstanding any other provision of these Exchangeable Share provisions, the Exchangeable Shares that are the subject of a Retraction Request may not be purchased by CallCo if such Exchangeable Shares are held by or on behalf of a Person in the United States or a U.S. Person. HOC or CallCo, as the case may be, (i) shall deliver or cause the Transfer Agent to deliver to the relevant holder, at the address of the holder recorded in the securities register of HOC for the Exchangeable Shares or at the address specified in the holder’s Retraction Request or by holding for pick-up by the holder at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC by notice to the holders of Exchangeable Shares, certificates representing the Ordinary Shares (which shares shall be duly issued as fully paid and shall be free and clear of any lien, claim or encumbrance) registered in the name of the holder or in such other name as the holder may request, and, if applicable and on or before the payment date therefor, a cheque payable at par at any branch of the bankers of HOC or CallCo, as applicable, representing the aggregate Dividend Amount in payment of the total Retraction Price or the total Purchase Price, as the case may be, in each case, less any amounts withheld on account of tax required to be deducted and withheld therefrom, and such delivery of such certificates and cheques on behalf of HOC or by CallCo, as the case may be, or by the Transfer Agent shall be deemed to be payment of and shall satisfy and discharge all liability for the total Retraction Price or total Purchase Price, as the case may

268 be, to the extent that the same is represented by such share certificates and cheques (plus any tax deducted and withheld therefrom and remitted to the proper tax authority); or (ii) arrange for or cause the Transfer Agent to arrange for the credit of Ordinary Shares (which shares shall be duly issued as fully paid and shall be free and clear of any lien, claim or encumbrances) to a CREST account on behalf of the relevant holder and if applicable, deliver to the relevant holder, at the address of the holder recorded in the securities register of HOC for the Exchangeable Shares or at the address specified in the holder’s Retraction Request or by holding for pick-up by the holder at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC by notice to the holders of Exchangeable Shares, a cheque payable at par at any branch of the bankers of HOC or CallCo, as applicable, representing the aggregate Dividend Amount in payment of the total Retraction Price or the total Purchase Price, as the case may be, in each case, less any amounts withheld on account of tax required to be deducted and withheld therefrom, and such CREST account credits and cheques on behalf of HOC or by CallCo, as the case may be, or by the Transfer Agent shall be deemed to be payment of and shall satisfy and discharge all liability for the total Retraction Price or total Purchase Price, as the case may be, to the extent that the same is represented by such CREST account credits and cheques (plus any tax deducted and withheld therefrom and remitted to the proper tax authority). On and after the close of business on the Retraction Date, the holder of the Retracted Shares shall cease to be a holder of such Retracted Shares and shall not be entitled to exercise any of the rights of a holder in respect thereof, other than the right to receive his proportionate part of the total Retraction Price or total Purchase Price, as the case may be, unless upon surrender of the Retracted Shares in accordance with the foregoing provisions payment of the total Retraction Price or the total Purchase Price, as the case may be, shall not be made as provided in this Part X, section 6.3(e), in which case the rights of such holder shall remain unaffected until the total Retraction Price or the total Purchase Price, as the case may be, has been paid in the manner hereinbefore provided. On and after the close of business on the Retraction Date, provided that the surrender of the Retracted Shares and payment of the total Retraction Price or the total Purchase Price, as the case may be, has been made in accordance with the foregoing provisions and subject to the relevant entries being made in the register of members of the Company, the holder of the Retracted Shares so redeemed by HOC or purchased by CallCo shall thereafter be considered and deemed for all purposes to be a holder of the Ordinary Shares delivered to it. Notwithstanding any other provision of this Article 6, HOC shall not be obligated to redeem Retracted Shares specified by a holder in a Retraction Request to the extent that such redemption of Retracted Shares would be contrary to solvency requirements or other provisions of applicable law. If HOC believes that on any Retraction Date it would not be permitted by any of such provisions to redeem the Retracted Shares tendered for redemption on such date, and provided that CallCo shall not have exercised the CallCo Redemption Call Right with respect to the Retracted Shares, HOC shall only be obligated to redeem Retracted Shares specified by a holder in a Retraction Request to the extent of the maximum number that may be so redeemed (rounded down to a whole number of shares) as would not be contrary to such provisions and shall notify the holder at least two Business Days prior to the Retraction Date as to the number of Retracted Shares which will not be redeemed by HOC. In any case in which the redemption by HOC of Retracted Shares would be contrary to solvency requirements or other provisions of applicable law, HOC shall redeem Retracted Shares in accordance with this Part X, section 6.3(e) on a pro rata basis and shall either issue to each holder of Retracted Shares a new certificate, at the expense of HOC, or deposit, electronically or otherwise, with the applicable nominee, Exchangeable Shares, representing the Retracted Shares not redeemed by HOC pursuant to this Part X, section 6.3(e). Provided that the Retraction Request is not revoked by the holder in the manner specified in this Part X, section 6.3(e), the holder of any such Retracted Shares not redeemed by HOC pursuant to this Part X, section 6.3(e) of these share provisions as a result of solvency requirements or other provisions of applicable law shall be deemed by giving the Retraction Request, subject to the immediately following sentence, to require the Company to purchase such Retracted Shares from such holder on the Retraction Date or as soon as practicable thereafter on payment by

269 the Company to such holder of the Purchase Price for each such Retracted Share, all as more specifically provided in the Voting and Exchange Trust Agreement. Notwithstanding the immediately preceding sentence, the Company will not be required to purchase any Retracted Shares form holders thereof pursuant to this Part X, section 6.3(e) or the Voting and Exchange Trust Agreement if such holder is a Person in the United States or a U.S. Person. A holder of Retracted Shares may, by notice in writing given by the holder to HOC in accordance with Part X, section 6.3(m) before the close of business on the Business Day immediately preceding the Retraction Date, withdraw its Retraction Request, in which event such Retraction Request shall be null and void and, for greater certainty, the revocable offer constituted by the Retraction Request to sell the Retracted Shares to CallCo shall be deemed to have been revoked. (f) Redemption of Exchangeable Shares by HOC Subject to applicable law, and provided CallCo has not exercised the CallCo Redemption Call Right, HOC shall on the Redemption Date redeem all but not less than all of the outstanding Exchangeable Shares for an amount per share equal to the Current Market Price of an Ordinary Share on the last Business Day prior to the Redemption Date (the ‘‘Heritage Redemption Right’’), which shall be satisfied in full by HOC causing to be delivered to each holder of Exchangeable Shares one Ordinary Share for each Exchangeable Share held by such holder, together with the full amount of all declared and unpaid dividends on each such Exchangeable Share held by such holder on any dividend record date which occurred prior to the Redemption Date (the ‘‘Redemption Price’’). In any case of a redemption of Exchangeable Shares under this Part X, section 6.3(f), HOC shall, at least sixty (60) days before the Redemption Date (other than a Redemption Date established in connection with a Company Control Transaction, an Exchangeable Share Voting Event or an Exempt Exchangeable Share Voting Event), send or cause to be sent to each holder of Exchangeable Shares a notice in writing of the redemption by HOC or the purchase by CallCo under the CallCo Redemption Call Right, as the case may be, of the Exchangeable Shares held by such holder. In the case of a Redemption Date established in connection with a Company Control Transaction, an Exchangeable Share Voting Event and an Exempt Exchangeable Share Voting Event, the written notice of redemption by HOC or the purchase by CallCo under the CallCo Redemption Call Right will be sent on or before the Redemption Date, on as many days prior written notice as may be determined by the HOC Board of Directors to be reasonably practicable in the circumstances. In any such case, such notice shall set out the formula for determining the Redemption Price or the Redemption Call Purchase Price, as the case may be, the Redemption Date and, if applicable, particulars of the HOC Redemption Call Right. On or after the Redemption Date and subject to the exercise by CallCo of the CallCo Redemption Call Right, HOC shall cause to be delivered to the holders of the Exchangeable Shares to be redeemed the Redemption Price for each such Exchangeable Share, upon surrender at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC in such notice of the Exchangeable Shares, together with such other documents and instruments as may be required to effect a transfer of Exchangeable Shares under the ABCA and the constating documents of HOC and such additional documents and instruments as the Transfer Agent may reasonably require. Payment of the total Redemption Price for such Exchangeable Shares, together with payment of such dividends, shall be made either (i) by delivery to each holder, at the address of the holder recorded in the securities register of HOC or by holding for pick-up by the holder at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC in such notice, certificates representing Ordinary Shares (which shares shall be duly issued as fully paid and shall be free and clear of any lien, claim or encumbrance) and, if applicable, a cheque of HOC payable at par at any branch of the bankers of HOC in payment of any such dividends, in each case, less any amounts withheld on account of tax required to be deducted and withheld therefrom; or

270 (ii) by arranging for the credit of Ordinary Shares (which shares shall be duly issued as fully paid and shall be free and clear of any lien, claim or encumbrances) to CREST accounts on behalf of each holder and, if applicable, delivery to each holder, at the address of the holder recorded in the securities register of HOC or by holding for pick-up by the holder at the registered office of HOC or at any office of the Transfer Agent as may be specified by HOC in such notice, a cheque of HOC payable at par at any branch of the bankers of HOC in payment of any such dividends, in each case, less any amounts withheld on account of tax required to be deducted and withheld therefrom). On and after the Redemption Date, the holders of the Exchangeable Shares called for redemption shall cease to be holders of such Exchangeable Shares and shall not be entitled to exercise any of the rights of holders in respect thereof, other than the right to receive their proportionate part of the total Redemption Price and any such dividends, unless payment of the total Redemption Price and any such dividends for such Exchangeable Shares shall not be made upon surrender of Exchangeable Shares in accordance with the foregoing provisions, in which case the rights of the holders shall remain unaffected until the total Redemption Price and any such dividends have been paid in the manner hereinbefore provided. HOC shall have the right at any time after the sending of notice of its intention to redeem the Exchangeable Shares as aforesaid to deposit or cause to be deposited the total Redemption Price for, and the full amount of such dividends on (except as provided in this Part X, section 6.3(f)), the Exchangeable Shares so called for redemption, or such of the said Exchangeable Shares represented by certificates that have not at the date of such deposit been surrendered by the holders thereof in connection with such redemption, in a custodial account with any chartered bank or trust company in Canada named in such notice, less any amounts withheld on account of tax required to be deducted and withheld therefrom. Upon the later of such deposit being made and the Redemption Date, the Exchangeable Shares in respect whereof such deposit shall have been made shall be redeemed and the rights of the holders thereof after such deposit or Redemption Date, as the case may be, shall be limited to receiving their proportionate part of the total Redemption Price and such dividends for such Exchangeable Shares so deposited, against surrender of the Exchangeable Shares held by them in accordance with the foregoing provisions. Upon such payment or deposit of the total Redemption Price and the full amount of such dividends and subject to the relevant entries being made in the register of members of the Company, the holders of the Exchangeable Shares shall thereafter be considered and deemed for all purposes to be holders of the Ordinary Shares delivered to them or the custodian on their behalf. (g) Purchase for cancellation (i) Subject to applicable law and notwithstanding anything in this Part X, section 6.3(g), HOC may, at any time and from time to time purchase for cancellation all or any part of the Exchangeable Shares by private agreement with any holder of Exchangeable Shares for consideration consisting of Ordinary Shares. (ii) Subject to applicable law and the articles of HOC, HOC may at any time and from time to time purchase for cancellation all or any part of the outstanding Exchangeable Shares at any price by tender to all the holders of record of Exchangeable Shares then outstanding or through the facilities of any stock exchange on which the Exchangeable Shares are listed or quoted at any price per share. If in response to an invitation for tenders under the provisions of this Part X, section 6.3(g), more Exchangeable Shares are tendered at a price or prices acceptable to HOC than HOC is prepared to purchase, the Exchangeable Shares to be purchased by HOC shall be purchased as nearly as may be pro rata according to the number of shares tendered by each holder who submits a tender to HOC, provided that when shares are tendered at different prices, the pro rating shall be effected (disregarding fractions) only with respect to the shares tendered at the price at which more shares were tendered than HOC is prepared to purchase after HOC has purchased all the shares tendered at lower prices. If part only of the Exchangeable Shares represented by any certificate shall be purchased a new certificate for the balance of such shares shall be issued at the expense of HOC.

271 (h) Voting rights Except as required by applicable law and by Part X, section 6.3(i) below, the holders of the Exchangeable Shares shall not be entitled as such to receive notice of or to attend any meeting of the shareholders of HOC or to vote at any such meeting. The holders of the Exchangeable Shares shall, however, be entitled to notice of meetings of the shareholders called for the purpose of authorizing the dissolution of HOC or the sale, lease or exchange or all or substantially all of the property of HOC other than in the ordinary business of HOC. (i) Amendment and approval (i) The rights, privileges, restrictions and conditions attaching to the Exchangeable Shares may be added to, changed or removed but only with the approval of the holders of the HOC Common Shares given in accordance with the ABCA and the approval of the holders of the Exchangeable Shares given as hereinafter specified. (ii) Any approval given by the holders of the Exchangeable Shares to add to, change or remove any right, privilege, restriction or condition attaching to the Exchangeable Shares or any other matter requiring the approval or consent of the holders of the Exchangeable Shares shall be deemed to have been sufficiently given if it shall have been given in accordance with applicable law subject to a minimum requirement that such approval be evidenced by resolution passed by not less than two-thirds of the votes cast on such resolution at a meeting of holders of Exchangeable Shares duly called and held at which the holders of at least 25 per cent. of the outstanding Exchangeable Shares at that time are present or represented by proxy; provided that if at any such meeting the holders of at least 25 per cent. of the outstanding Exchangeable Shares at that time are not present or represented by proxy within one-half hour after the time appointed for such meeting, then the meeting shall be adjourned to such date not less than five days thereafter and to such time and place as may be designated by the Chairman of such meeting. At such adjourned meeting the holders of Exchangeable Shares present or represented by proxy thereat may transact the business for which the meeting was originally called and a resolution passed thereat by the affirmative vote of not less than two-thirds of the votes cast on such resolution at such meeting shall constitute the approval or consent of the holders of the Exchangeable Shares. (j) Reciprocal changes, etc. in respect of Ordinary Shares Each holder of an Exchangeable Share acknowledges that the Support Agreement provides, in part, that so long as Exchangeable Shares not owned by the Company or its Affiliates are outstanding, the Company will not without the prior approval of HOC and CallCo and the prior approval of the holders of the Exchangeable Shares given in accordance with Part X, section 6.3(i) of these share provisions: (i) issue or distribute Ordinary Shares (or securities exchangeable for or convertible into or carrying rights to acquire Ordinary Shares) to the holders of all or substantially all of the then outstanding Ordinary Shares by way of stock dividend or other distribution, other than an issue of Ordinary Shares (or securities exchangeable for or convertible into or carrying rights to acquire Ordinary Shares) to holders of Ordinary Shares who exercise an option to receive dividends in Ordinary Shares (or securities exchangeable for or convertible into or carrying rights to acquire Ordinary Shares) in lieu of receiving cash dividends; (ii) issue or distribute rights, options or warrants to the holders of all or substantially all of the then outstanding Ordinary Shares entitling them to subscribe for or to purchase Ordinary Shares (or securities exchangeable for or convertible into or carrying rights to acquire Ordinary Shares); or (iii) issue or distribute to the holders of all or substantially all of the then outstanding Ordinary Shares: (a) shares or securities of the Company of any class other than Ordinary Shares (other than shares convertible into or exchangeable for or carrying rights to acquire Ordinary Shares);

272 (b) rights, options or warrants other than those referred to above; (c) evidences of indebtedness of the Company; or (d) assets of the Company, unless the economic equivalent on a per share basis of such rights, options, securities, shares, evidences of indebtedness or other assets is issued or distributed simultaneously to holders of the Exchangeable Shares. Each holder of an Exchangeable Share acknowledges that the Support Agreement further provides, in part, that so long as Exchangeable Shares not owned by the Company or its Affiliates are outstanding, the Company will not without the prior approval of HOC and CallCo and the prior approval of the holders of the Exchangeable Shares given in accordance with Part X, section 6.3(i) of these share provisions: (i) subdivide, redivide or change the then outstanding Ordinary Shares into a greater number of Ordinary Shares; (ii) reduce, combine, consolidate or change the then outstanding Ordinary Shares into a lesser number of Ordinary Shares; or (iii) reclassify or otherwise change the Ordinary Shares or effect an amalgamation, merger, reorganisation or other transaction affecting the Ordinary Shares, unless the same or an economically equivalent change shall simultaneously be made to, or in the rights of the holders of, the Exchangeable Shares. The Support Agreement further provides, in part, that the aforesaid provisions of the Support Agreement shall not be changed without the approval of the holders of the Exchangeable Shares given in accordance with Part X, section 6.3(i) of these share provisions (other than certain amendments which are not prejudicial to the rights or interests of the holders of Exchangeable Shares). Each holder of an Exchangeable Share acknowledges that the Support Agreement further provides, in part, that the Company will not, without the prior approval of HOC and the prior approval of the holders of the Exchangeable Shares given in accordance with Part X, section 6.3(i) as long as any outstanding Exchangeable Shares are owned by any person or entity other than the Company or any of its Affiliates, cease to remain the direct or indirect beneficial owner of all of the issued and outstanding voting shares in the capital of HOC, CallCo and DutchCo. Further, during the term of the Voting and Exchange Trust Agreement, the Company will not, without the consent of the holders at the relevant time of Exchangeable Shares given in accordance with Part X, section 6.3(i) issue any shares of its capital stock in the same class as the Special Voting Share and will not amend or modify the Voting and Exchange Trust Agreement except by an agreement in writing executed by the Company, HOC and the Trustee, and approved by the Beneficiaries in accordance with Part X, section 6.3(i) of these share provisions. If the Company at any time after the date hereof, consummates any transaction (whether by way of reconstruction, arrangement, reorganisation, consolidation, merger, transfer, sale, lease or otherwise) whereby all or substantially all of its undertaking, property and assets would become the property of any other Person or, in the case of a merger, of the continuing corporation or other entity resulting therefrom (such other Person or continuing corporation (or, in the event of a merger, amalgamation or similar transaction pursuant to which holders of shares in the capital of the Company are entitled to receive shares or other ownership interest in the capital of any corporation or other legal entity other than such other Person or continuing corporation, then such corporation or other legal entity in which holders of shares in the capital of the Company are entitled to receive an interest) is herein called the ‘‘Company Successor’’) then, provided that the Company Successor is bound, or has agreed to be bound by the provisions of the Voting and Exchange Trust Agreement and Support Agreement and to assume the obligations of the Company thereunder to the satisfaction of the HOC Board of Directors, all references in these share provisions to Ordinary Shares shall be deemed to be references to the shares of the Company Successor, without amendment to these share provisions or any further action whatsoever. For greater certainty, if a transaction described in

273 this Part X, section 6.3(j) results in holders of Exchangeable Shares being entitled to exchange their Exchangeable Shares for shares of a Company Successor in a different ratio then that set out in these share provisions, then these share provisions shall be deemed to be amended to refer to such different ratio(s). (k) Actions by HOC under Support Agreement HOC will take all such actions and do all such things as shall be necessary or advisable to perform and comply with and to ensure performance and compliance by the Company, DutchCo, CallCo and HOC with all provisions of the Support Agreement applicable to the Company, DutchCo, CallCo and HOC, respectively, in accordance with the terms thereof including, without limitation, taking all such actions and doing all such things as shall be necessary or advisable to enforce to the fullest extent possible for the direct benefit of HOC all rights and benefits in favour of HOC under or pursuant to such agreement. HOC shall not propose, agree to or otherwise give effect to any amendment to, or waiver or forgiveness of its rights or obligations under the Support Agreement without the approval of the holders of the Exchangeable Shares given in accordance with Part X, section 6.3(i) of these share provisions other than such amendments, waivers and/or forgiveness as may be necessary or advisable for the purposes of (i) adding to the covenants of any or all parties to such agreement for the protection of the Company or the holders of the Exchangeable Shares thereunder provided that the board of directors of each of HOC, CallCo, DutchCo and the Company shall be of the good faith opinion that such additions will not be prejudicial to the rights or interests of the holders of Exchangeable Shares; (ii) making such provisions or modifications not inconsistent with such agreement as may be necessary or desirable with respect to matters or questions arising thereunder which, in the good faith opinion of the board of directors of each of HOC, CallCo, DutchCo and the Company, it may be expedient to make, provided that each such board of directors shall be of the good faith opinion, after consultation with legal counsel, that such provisions and modifications will not be prejudicial to the interests of the holders of the Exchangeable Shares; or (iii) making such changes in or corrections to such agreement which, on the advice of counsel to HOC, CallCo, DutchCo and the Company, are required for the purpose of curing or correcting any ambiguity or defect or inconsistent provision or clerical omission or mistake or manifest error contained therein, provided that the board of directors of each of HOC, CallCo, DutchCo and the Company shall be of the good faith opinion, after consultation with counsel, that such changes or corrections will not be prejudicial to the interests of the holders of the Exchangeable Shares. (l) Legend; Call Rights The certificates evidencing the Exchangeable Shares shall contain or have affixed thereto a legend in form and on terms approved by the HOC Board of Directors, with respect to the Support Agreement, the provisions of the Plan of Arrangement relating to the Liquidation Call Right, the Retraction Right and the CallCo Redemption Call Right, and the Voting and Exchange Trust Agreement (including the provisions with respect to the voting rights, exchange rights and automatic exchange thereunder). Each holder of an Exchangeable Share, whether of record or beneficial, by virtue of becoming and being such a holder shall be deemed to acknowledge each of the Liquidation Call Right and the CallCo Redemption Call Right, in each case, in favour of CallCo, and the overriding nature thereof in connection with the liquidation, dissolution or winding-up of HOC or the redemption of Exchangeable Shares, as the case may be, and to be bound thereby in favour of CallCo as therein provided. HOC, CallCo, DutchCo, the Company and the Transfer Agent shall be entitled to deduct and withhold from any dividend or consideration otherwise payable to any holder of Exchangeable Shares such amounts as HOC, CallCo, DutchCo, the Company or the Transfer Agent is required to deduct and withhold with respect to such payment under the Income Tax Act (Canada), the laws of the Netherlands, the laws of the United Kingdom, the laws of Jersey or

274 any provision of provincial, territorial, state, local or foreign tax law, in each case, as amended. To the extent that such amounts are so withheld, such withheld amounts shall be treated for all purposes hereof as having been paid to the holder of such Exchangeable Shares in respect of which such deduction and withholding was made, provided that such withheld amounts are actually remitted to the appropriate taxing authority. To the extent that the amount so required or permitted to be deducted or withheld from any payment to a holder exceeds the cash portion of the consideration otherwise payable to the holder, HOC, CallCo, the Company and the Transfer Agent are hereby authorized to sell or otherwise dispose of such portion of consideration on behalf of the holder of the Exchangeable Shares as is necessary to provide sufficient funds to HOC, CallCo, DutchCo, the Company or the Transfer Agent, as the case may be, to enable it to comply with such deduction or withholding requirement and HOC, CallCo, DutchCo, the Company or the Transfer Agent shall notify the holder thereof and remit any unapplied balance of the net proceeds of such sale. (m) Notices Any notice, request or other communication to be given to HOC by a holder of Exchangeable Shares shall be in writing and shall be valid and effective if given by mail (postage prepaid) or by telecopy or by delivery to the registered office of HOC and addressed to the attention of the President. Any such notice, request or other communication, if given by mail, telecopy or delivery, shall only be deemed to have been given and received upon actual receipt thereof by HOC. Any presentation and surrender by a holder of Exchangeable Shares to HOC or the Transfer Agent of certificates representing Exchangeable Shares in connection with the liquidation, dissolution or winding-up of HOC or the retraction or redemption of Exchangeable Shares shall be made by registered mail (postage prepaid) or by delivery to the registered office of HOC or to such office of the Transfer Agent as may be specified by HOC, in each case, addressed to the attention of the President of HOC. Any such presentation and surrender of certificates shall only be deemed to have been made and to be effective upon actual receipt thereof by HOC or the Transfer Agent, as the case may be. Any such presentation and surrender of certificates made by registered mail shall be at the sole risk of the holder mailing the same. Any notice, request or other communication to be given to a holder of Exchangeable Shares by or on behalf of HOC shall be in writing and shall be valid and effective if given by mail (postage prepaid) or by delivery to the address of the holder recorded in the securities register of HOC or, in the event of the address of any such holder not being so recorded, then at the last known address of such holder. Any such notice, request or other communication, if given by mail, shall be deemed to have been given and received on the third Business Day following the date of mailing and, if given by delivery, shall be deemed to have been given and received on the date of delivery. Accidental failure or omission to give any notice, request or other communication to one or more holders of Exchangeable Shares shall not invalidate or otherwise alter or affect any action or proceeding to be taken by HOC pursuant thereto.

7. DIRECTORS’ AND OTHERS’ INTERESTS Shareholdings

7.1 As at the date of this document, the Directors and the Senior Manager have no interests in the share capital of the Company. The table below sets out the expected interests of the Directors

275 (and of persons connected with them) and Senior Manager in the share capital of the Company as at Admission:

Number of Percentage of Director/Senior Manager Ordinary Shares Issued Share Capital Michael Hibberd ...... 0 0% Anthony Buckingham(1) ...... 84,540,340 33% Paul Atherton ...... 1,140,000 0.5% Gregory Turnbull ...... 300,070 0.1% John McLeod ...... 20,000 0 General Sir Michael Wilkes ...... 0 0 Brian Smith ...... 0 0

(1) Mr. Anthony Buckingham’s Ordinary Shares include the Ordinary Shares held by the Major Shareholder, a company owned and controlled by Mr. Buckingham. The Directors are expected to be interested in 86,000,410 Ordinary Shares immediately following Admission. This is based on their interest in 8,600,041 HOC Common Shares as at 28 March 2008, being the latest practicable date prior to the publication of this document. 7.2 On Admission, the Directors and the Senior Manager hold the following Options granted pursuant to the Scheme (the terms of which are summarised in section 8 of this Part X): Number of Director/Senior Manager Options Expiry Date Exercise Price per Ordinary Share(1) Michael Hibberd ...... 1,150,000 23 June 2011; 150,000 Options at Cdn$1.66; 14 December 2011; 750,000 Options at Cdn$2.91; 21 December 2012 250,000 Options at Cdn$5.01 Anthony Buckingham ...... 10,129,510 20 May 2010; 500,000 Options at Cdn$0.97; 14 December 2011; 9,129,510 Options at Cdn$2.91; 21 December 2012 500,000 Options at Cdn$5.01 Paul Atherton ...... 2,875,000 20 May 2010; 1,250,000 Options at Cdn$0.97; 14 December 2011; 1,125,000 Options at Cdn$2.91; 21 December 2012 500,000 Options at Cdn$5.01 Gregory Turnbull ...... 600,000 20 May 2010; 150,000 Options at Cdn$.97; 14 December 2011; 300,000 Options at Cdn$2.91; 21 December 2012 150,000 Options at Cdn$5.01. John McLeod ...... 550,000 20 May 2010 100,000 Options at C$9.70 14 December 2011 300,000 Options at C$29.14 21 December 2012 150,000 Options at C$50.06 Brian Smith ...... 1,200,000 14 December 2011; 900,000 Options at Cdn$2.91; 21 December 2012 300,000 Options at Cdn$5.01.

(1) The final exercise prices will be converted into pounds sterling on the date of Admission using the exchange rate in effect on such date.

7.3 Save as set out in this section and in section 7.1 above, the Company is not aware of any person who has or will immediately following Admission have an interest which represents 3 per cent. or more of the issued voting share capital of the Company: Number of Percentage of Issued Shareholder Ordinary Shares Share Capital Major Shareholder ...... 80,599,460 32%

7.4 Save as detailed in sections 7.1, 7.2 and 7.3 above, the Company is not aware of any person who either as at the date of this document or immediately following Admission exercises, or could exercise, directly or indirectly, jointly or severally, control over the Company.

276 7.5 None of the major shareholders of the Company set out above has different voting rights from any other holder of Ordinary Shares in respect of any Ordinary Share held by them. 7.6 Service Contracts/Terms of Employment Mr. Anthony Buckingham entered into an executive service agreement with the Company, dated 28 March 2008, in which he agreed to act as Chief Executive Officer. The agreement is terminable on not less than 24 months’ written notice by the Company at any time or 6 months notice by Mr. Buckingham at any time; in addition, the Company may terminate the agreement and make payment in lieu of notice. Mr. Buckingham’s basic annual salary is £675,000 and he is eligible to receive an annual performance-related bonus which will be determined at the discretion of the Board. Mr. Buckingham has also been granted options under the Scheme. Mr. Buckingham is entitled to the benefits of private medical insurance, life insurance, an allowance in the amount of £100,000 and executive participation in the retirement and welfare benefit schemes of the Company from time to time. In the event of a change of control of the Company, if Mr. Buckingham resigns or the Company terminates his appointment within twenty-four months of such change of control, he shall be entitled to an immediate payment in lieu of notice of a sum equivalent to three times his annual salary. Mr. Paul Atherton entered into an executive service agreement with the Company, dated 28 March 2008, in which he agreed to act as Chief Financial Officer. The agreement is terminable on not less than 24 months’ written notice by the Company at any time or 6 months’ notice by Mr. Atherton at any time, in addition, the Company may terminate the agreement and make payment in lieu of notice. Mr. Atherton’s annual salary is £500,000 and he is eligible to receive an annual performance-related bonus which will be determined at the discretion of the board. Mr. Atherton has also been granted options under the Scheme. Mr. Atherton is entitled to the benefits of private medical insurance, life insurance, an allowance in the amount of £77,500 and executive participation in the retirement and welfare benefit schemes of the Company from time to time. In the event of a change of control of the Company, if Mr. Atherton resigns or the Company terminates his appointment within twenty-four months of such change of control, he shall be entitled to an immediate payment in lieu of notice of a sum equivalent to three times his annual salary. Mr. Michael Hibberd, Mr. Gregory Turnbull, John McLeod and General Sir Michael Wilkes are engaged as non-executive directors of the Company under the letters of appointment dated 28 March 2008 respectively. Pursuant to these, such non-executive directors each receive an annual fee of £80,000, £50,000, £50,000, and £80,000, respectively plus an additional fee of £2,000 respectively (or such other amount as the board in its sole discretion deems appropriate) per day worked in excess of 20 days per annum. Mr. Hibberd’s, Mr. Turnbull’s, Mr. McLeod’s and General Sir Michael Wilkes’ agreements are terminable on three months’ written notice by either party. Subject to early termination, Mr. Hibberd, Mr. Turnbull, Mr. McLeod and General Sir Michael Wilkes are each to be appointed for an initial period of 2, 1, 1 and 3 years, respectively (and for a period of a further 3 years after the initial term of their appointments). Mr. Hibberd and Mr. Turnbull are entitled to a change of control bonus (relating to a change of control in HOC) in the amount of $75,000 plus a pro-rata amount of his previous year’s bonus multiplied by a stock price performance factor. In addition to the fees due to General Sir Michael Wilkes as described above, he also received a payment of £50,000 upon joining the board of the Company. All the directors (both executive and non-executive (excluding General Sir Michael Wilkes who is not a director of HOC)) are entitled to a $75,000 payment in the event they are asked to resign from the board of HOC in any event other than as result of a change of control. No member of the administrative, management or supervisory bodies’ service contracts with the Company or any member of the Group provide for benefits upon termination of employment. 7.7 Save as detailed in section 7.6 above, there are no other service contracts between any of the Directors and the Group providing for benefit upon termination of employment.

277 7.8 In the financial year ended 31 December 2006, the total remuneration paid (including contingent or deferred compensation) and benefits in kind granted (under any description whatsoever) to each of the Directors and Senior Managers by members of the Group was: Remuneration Paid (Including Contingent Director/Senior Manager or Deferred Compensation) Benefits in Kind Michael Hibberd ..... Annual directors’ fee of Cdn$15,000; 90,000 HOC Options Bonus Cdn$116,630. Anthony Buckingham . . Directors’ salary of $262,629; 912,951 HOC Options. Bonus $587,430. Paul Atherton ...... Directors’ salary of $626,808; 112,500 HOC Options. Bonus $489,525. Gregory Turnbull ..... Annual directors’ fees of Cdn$18,000; 30,000 HOC Options Bonus of Cdn$34,989. Brian Smith ...... Annual salary of $304,908; 90,000 HOC Options Bonus of $391,620.

Other Interests 7.9 The Directors and Senior Managers: (a) other than directorships of Group Companies the Directors, are or have been directors or partners of the following companies and partnerships at any time in the previous five years:

Position still Director/Senior Manager Position Company/Partnership held (yes/no) Michael Hibberd Director Iteration Energy Ltd. Yes Director AltaCanada Energy Corp. Yes Director Challenger Energy Corp. Yes Director Deer Creek Energy Ltd. No Director Fern Energy Ltd. Yes Chairman and CEO MJH Services Inc. Yes Director Pan Orient Energy Corp. Yes Director Rally Energy Corp. No Director Ramtelecom Inc. Yes Chairman and CEO Sunshine Oilsands Ltd. Yes Director Zapata Energy Corp. Yes Director 763846 Alberta Ltd. Yes Paul Atherton Director SeaDragon Offshore Limited Yes Partner Wallgrave Partnership No Director Plaza 107 Limited No Trustee/Treasurer Royal School of Mines No Association

278 Position still Director/Senior Manager Position Company/Partnership held (yes/no) Gregory Turnbull Director Action Energy Inc. Yes Director BNP Resources Inc. Yes Director Castle Rock Petroleum Ltd. No Director Clearwater Energy Inc. Yes Director Crescent Point Energy Ltd. No Director Crescent Point Energy Trust Yes Director Flagship Energy Inc. Yes Director Flowing Energy Corp. No Director Mohave Exploration & Yes Production Inc. Director Rally Energy Corp. No Director Seaview Energy Inc. Yes Director Seventh Energy Ltd. No Director Storm Energy Ltd. No Officer Storm Exploration Inc. Yes Director Sunshine Oilsands Ltd. Yes Director Trimox Energy Inc. No John McLeod Director, Chairman Consolidated Beacon Yes Resources Ltd. Director, President, California Oil & Gas Yes CEO Corporation Director Range Minerals Inc. No Director Highview Resources Ltd. No Director Paris Energy Inc. Yes Director Calstar Oil & Gas Ltd. No Director Tuscany Energy Ltd. Yes Director Diaz Resources Ltd. Yes Director Petroworth Resources Inc. No Director Keeper Resources Inc. Yes Director Castlerock Petroleum Ltd. No General Sir Michael Chairman Cyberview Technology Ltd. Yes Wilkes Chairman of PegasusBridge Fund Yes Advisory Board Management Limited Chairman Britam Defence Ltd. Yes Non-Executive Stanley Gibbons Group Ltd. Yes Director Deputy Chairman C.I. Traders No Non-Executive Tryco Ltd. Yes Director Chairman Chiltern Limited No (b) have no convictions in relation to fraudulent offences within the previous five years; (c) have not been associated with any bankruptcies, receiverships or liquidations while acting in the capacity of director or senior manager of any company within the previous five years; and (d) have not received any official public incrimination and/or sanction by statutory or regulatory authorities (including designated professional bodies) and have never been disqualified by a court from acting as a director of a company or from acting in the management or conduct of the affairs of any company within the previous five years. 7.10 Gregory Turnbull is a partner of McCarthy Tetrault´ LLP, a firm of solicitors which has advised the Group as to Canadian law in respect of the application for Admission. McCarthy Tetrault´ LLP is a related party of McCarthy Tetrault´ Registered Foreign Lawyers and Solicitors (together ‘‘McCarthy Tetrault’’)´ which has advised the Group as to English law in respect of the application for Admission. McCarthy Tetrault´ will receive fees from the Company in respect of their advice and will continue to provide services to the Group following Admission.

279 7.11 Save for the directorships and partnerships disclosed in section 7.9(a) and save for section 7.10 above, none of the Directors or Senior Managers have any potential conflicts of interests between their duties to the Company and their private interests or other duties. 7.12 Save as disclosed in section 7.11 above, no person has any interest, including conflicting ones, that is material to the Admission.

8. SUMMARY OF THE COMPANY’S 2008 REPLACEMENT SHARE OPTION SCHEME The terms of the Scheme are as follows: (a) Purpose and Participation The HOC Plan was originally implemented by HOC, and approved by the shareholders of HOC and the TSX in 2004. As a result of the reorganisation of the Group in accordance with the terms of the Arrangement, holders of HOC Options will exchange each outstanding option to acquire a HOC Common Share for an Option to acquire an Ordinary Share of the Company (on a 1:10 basis), at which point the HOC Plan will then be cancelled. As a result of the reorganisation, the Company has adopted the Scheme on 18 March 2008 which is in substance and form substantially the same stock option plan as the HOC Plan. The purpose of the Scheme is to act as a replacement to the HOC Plan and to honour the options originally granted under the HOC Plan Options by granting holders of HOC Options the option to purchase Ordinary Shares. The Scheme will be administered by the Board. There shall be no further options granted under this Scheme.

(b) Number of Shares Under the Scheme The maximum number of Ordinary Shares that may be issued from time to time pursuant to Options granted under the Scheme is that number required to replace the HOC Options that were granted under the HOC Plan and were still in existence prior to their cancellation, being 24,545,340 Ordinary Shares.

(c) Term and Termination; Vesting The Company will deliver to each optionholder an option agreement which will include a date on which the Option expires. If such expiry date occurs during or within 10 days after the last day of a close period (meaning any period during which a policy of the Company prevents an insider from trading in the Ordinary Shares), the expiry date for the Option will be the last day of such 10 day period. The Options may be subject to vesting periods, as were determined by the Directors at the time the Options were granted and will be set out in the option agreements delivered to the optionholders. If an optionholder dies, only the portion of the Option that is exercisable at the date of death of the optionholder may be exercised by the personal representatives of the optionholder during the period ending 6 months after the death of the optionholder, after which period all Options terminate. If an optionholder resigns his or her office or employment, or an optionholder’s contract as a consultant terminates at its normal termination date, only the portion of the Option that is exercisable at the termination date may be exercised by the optionholder during the period ending ninety 90 days after the termination date, after which period all Options expire. If the employment of an optionholder is terminated without cause, including a constructive dismissal, or an optionholder’s contract as a consultant is terminated by the Company before its normal termination date without cause, only the portion of the Option that is exercisable at the termination date may be exercised by the optionholder during the period ending 90 days after the termination date, after which period all Options expire. An Option will expire immediately upon the optionholder ceasing to be eligible for Options under the Scheme as a result of being dismissed from his or her office or employment for cause or an optionholder’s contract as a consultant being terminated before its normal termination date for cause, including where a person eligible for Options resigns his or her office or

280 employment or terminates his or her contract as a consultant after being requested to do so by the Company as an alternative to being dismissed or terminated by the Company for cause.

(d) Exercise Price The exercise price of each Option granted under the Scheme will be an amount determined by the Directors that ensures the optionholders are put in substantially the same position they were in prior to the Arrangement and the cancellation of the HOC Plan.

(e) Assignment An Option may be exercised only by the optionholder and is not assignable in law or in equity, and any purported assignment will be void and of no force and effect whatsoever.

(f) Exercise and Right to Postpone Exercise An optionholder (or the personal representative of a deceased optionholder) who wishes to exercise an Option may do so by delivering a notice to the Company specifying the number of Ordinary Shares in respect of which such Option is being exercised, accompanied by payment (by cheque, bank draft or wire transfer payable to the Company) for the aggregate exercise price for the Ordinary Shares. An Option may not be exercised for less than 100 Ordinary Shares at any one time, except where a smaller number of Ordinary Shares remains exercisable pursuant to an Option, in which case the Option may be exercised for such smaller number at one time. Each optionholder, upon becoming entitled to exercise an Option to purchase Ordinary Shares in accordance with his or her respective option agreement, shall thereafter be entitled to exercise the Option to purchase such Ordinary Shares at any time prior to the expiration or other termination of the option agreement or the option rights granted thereunder in accordance with such agreement. Nothing in the Scheme or option agreements obligates an optionholder to exercise an Option.

(g) Amendment, Termination and Approvals (i) The Directors may without the approval of the shareholders of the Company, at any time and from time to time, amend, suspend or terminate the Scheme at any time, provided that no such amendment, suspension or termination may be made without obtaining any required approval of any regulatory authority or stock exchange or materially prejudice the rights of any optionholder under any Option previously granted to the optionholder without the consent or deemed consent of the optionholder. (ii) Notwithstanding section (i) above, the Directors may not, without the approval of the shareholders of the Company, make amendments to the Scheme for any of the following purposes: A. to increase the maximum number of Ordinary Shares that may be issued pursuant to Options granted under the Scheme; B. to reduce the exercise price of Options to less than the market price; C. to reduce the exercise price of Options for the benefit of an insider; D. to extend the expiry date of Options for the benefit of an insider; E. to increase the maximum number of Ordinary Shares issuable that may be issued pursuant to Options granted under the Scheme; and F. to amend the provisions of the section entitled ‘‘Amendment and Termination’’ of the Scheme. (iii) The Directors may, at any time and from time to time, without the approval of the shareholders of the Company, amend any term of any outstanding Option (including, without limitation, the exercise price, vesting and expiry of the Option), provided that: A. any required approval of any regulatory authority or stock exchange is obtained;

281 B. if the amendments would reduce the exercise price or extend the expiry date of Options granted to insiders, approval of the shareholders of the Company must be obtained; C. the Directors would have had the authority to initially grant the Option under the terms as so amended; and D. the consent or deemed consent of the optionholder is obtained if the amendment would materially prejudice the rights of the optionholder under the Option.

9. PROPERTY, PLANT AND EQUIPMENT The Group’s material tangible fixed assets, including leasehold properties are as follows:

Freehold/ Property Description Location Leasehold Owner/ Tenant Expiry of Term Current Rent Head Office Jersey Rental BDO Alto Temporary Channel Agreement Islands Group Technical Offices London, U.K. Leasehold Grosvenor West End 28 September 2129 £29,500 per annum Properties/ Coatbridge Estates Limited Canadian Office Calgary Leasehold Consolidated Becon N/A Cdn$1,100 per Resources/HOC month Head-office in the KRI Erbil Rental Mrs Golala Salah January 2009 $2,600 per month Agreement Ahmad Ahawqi/ Heritage Middle East Operations office in the Sulymaniyah Rental Mr. Kameran Kader January 2009 $2,000 per month KRI Agreement Ahmad/Heritage Middle East

10. MATERIAL CONTRACTS The following are the only contracts (not being contracts entered into in the ordinary course of business) which have been entered into by member of the Group within two years immediately preceding the date of this document and which are, or may be, material or which have been entered into at any time by members of the Group and which contain any provision under which any member of the Group has any obligation or entitlement which is, or may be, material to the Group as at the date of this document: 10.1 Arrangement Agreement On 22 February 2008, HOC entered into an arrangement agreement with the Company, DutchCo and Alberta CallCo which provides for the reorganisation of the share capital of the HOC through the Plan of Arrangement pursuant to the Business Corporation Act (Alberta). The terms of the Arrangement Agreement are set out in section 1 of Part IX of this document. 10.2 Voting and Exchange Trust Agreement Also in connection with the Arrangement Agreement, HOC entered into a voting and exchange trust agreement with the Company, Alberta CallCo and the Trustee on 27 February 2008. Pursuant to the Voting and Exchange Trust Agreement, the Company will issue one Special Voting Share to the Trustee for the benefit of the Beneficiaries. The Special Voting Share will have the number of votes, which may be cast at any meeting at which holders of Ordinary Shares are entitled to vote, equal to the number of Exchangeable Shares outstanding at the relevant time. Each Beneficiary on the record date for any meeting at which holders of Ordinary Shares are entitled to vote will be entitled to instruct the Trustee to exercise those votes attached to the Special Voting Share for each Exchangeable Share held by such Beneficiary or to obtain a proxy from the Trustee entitling the Beneficiary to vote directly, at the relevant meeting, the votes attached to the Special Voting Share to which the Beneficiary is entitled.

282 All rights of a holder of Exchangeable Shares to exercise votes attached to the Special Voting Share will cease upon the exchange (whether by redemption, retraction or liquidation or through the Exchange Right (defined below)) of such Exchangeable Shares for Ordinary Shares. The Voting and Exchange Trust Agreement also provides for the grant by the Company to the Trustee of the Exchange Right, upon HOC facing certain insolvency events, to require the Company to purchase from each Beneficiary all or any part of the Exchangeable Shares held by the Beneficiary. The purchase price payable by the Company for each Exchangeable Share pursuant to the Exchange Right shall be satisfied in full by the Company delivering to each Beneficiary one Ordinary Share for each Exchangeable Share held by such Beneficiary plus, to the extent not paid by HOC, an additional amount equal to the full amount of all declared and unpaid dividends on each such Exchangeable Share. The Voting and Exchange Trust Agreement continues until the earlier of the following: (a) no outstanding Exchangeable Shares are held by a Beneficiary; (b) each of HOC and the Company elects in writing to terminate the trust created by the Voting and Exchange Trust Agreement and such termination is approved by the Beneficiaries; and (c) twenty-one (21) years after the date of the Voting and Exchange Trust Agreement. 10.3 Support Agreement In connection with the Arrangement Agreement, HOC, the Company, DutchCo and Alberta CallCo entered into a support agreement on 17 March 2008. Pursuant to the Support Agreement, for so long as any Exchangeable Shares remain outstanding, the Company has made certain covenants, to the fullest extent permitted by law, in favour of HOC including, but not limited to, the following: (a) the Company will not declare or pay dividends on Ordinary Shares unless HOC is able to declare and pay and simultaneously declares and pays, as the case may be, an equivalent dividend on the Exchangeable Shares; (b) the Company will advise HOC in advance of the declaration of any dividend by the Company; and (c) the Company will take all actions and do all things reasonably necessary to enable and permit HOC and Alberta CallCo to perform their obligations, if any, arising upon the liquidation, dissolution or winding up of HOC, the receipt of a Retraction Request, the exercise by Alberta CallCo of its right to purchase Exchangeable Shares that are the subject of a Retraction Request and the exercise and the exercise by Alberta CallCo of its right to purchase all Exchangeable Shares in the event of the a proposed liquidation, dissolution or winding up of HOC. The Company has agreed to take all such actions as are reasonably necessary to cause all Ordinary Shares deliverable in connection with Exchangeable Shares to be listed and posted for trading on all stock exchanges on which outstanding Ordinary Shares are listed. The Company has also agreed not to exercise any voting rights attached to the Exchangeable Shares owned by it or any of its affiliates on any matter considered at meetings of holders of Exchangeable Shares. Pursuant to the Support Agreement, HOC is required to notify the Company and Alberta CallCo of certain events, such as the liquidation, dissolution or winding up of HOC and the receipt of a Retraction Request. The Support Agreement shall continue until such time as no Exchangeable Shares are held by any person or entity other than the Company and its affiliates. 10.4 Relationship Agreement On 28 March 2008, the Company entered into a relationship agreement (the ‘‘Relationship Agreement’’) with Anthony Buckingham and the Major Shareholder, governing the relationship between the parties following Admission. At Admission, Mr Buckingham will own 33.2 per cent. of the voting rights attaching to the issued share capital of the Company following Admission, directly and indirectly through the Major Shareholder. The Relationship Agreement is conditional on

283 Admission taking place, and has been entered into to regulate certain aspects of the continuing relationship between the parties to ensure compliance with the Listing Rules. Pursuant to the terms of the Relationship Agreement, Mr. Buckingham agrees to exercise all powers of control, and procure (to the extent possible) that the Major Shareholder exercises all powers of control, in relation to the Company so as to ensure that: (i) at all times each of the Company and the other Group members is capable of carrying on, and does carry on, its business independently of Mr. Buckingham and the Major Shareholder and any of their associates, having regard to the interests of the Group, rather than for the benefit of any particular shareholder or group of shareholders in the Company; (ii) at all times the business and affairs of the Company shall be managed by the Board in accordance with the Articles and all applicable law and for the benefit of its shareholders as a whole; (iii) all transactions and relationships between any Group member and the Major Shareholder or Mr. Buckingham, or any of their associates are conducted on arm’s length terms and on a commercial basis in compliance with the Listing Rules; (iv) the requirements relating to transactions with related parties set out in Listing Rule 11 are complied with in relation to transactions between Mr. Buckingham, the Major Shareholder or any of their associates on the one hand and the Group on the other hand; and (v) the terms of the Relationship Agreement are complied with in all respects. All provisions of the Relationship Agreement are to remain in effect until the earlier of (i) whilst Mr. Buckingham and the Major Shareholder continue to own in aggregate an amount of shares in the Company representing no less than 25 per cent. of the rights attaching to the issued share capital of the Company entitled to vote at general meetings of the Company and (ii) 1 April 2010. The Relationship Agreement prescribes that at all times the Board shall be comprised of a majority of Directors who are independent of Mr. Buckingham, if the Board is comprised of fewer than six directors, no more than one Director may not be independent of Mr. Buckingham and any of his associates. If the Board is comprised of more than six directors, no more than one-third of the Directors may not be independent of Mr. Buckingham and his associates. Intra-group transfers are permitted by Mr. Buckingham or the Major Shareholder to any related undertakings, so long as any transferee agrees to be bound by the terms of the Relationship Agreement. The agreement also contains confidentiality provisions, whereby Mr. Buckingham agrees that he shall treat and keep, and procure that the Major Shareholder shall treat and keep, and shall use reasonable endeavours to ensure his associates treat and keep as strictly confidential all non-public information relating to the business, investments, finances and other matters of the Group in accordance with his Service Agreement as if all such persons were bound by the provisions of confidentiality in such agreement. 10.5 Sponsor’s Agreement On 28 March 2008, the Company, HOC, the Directors and the Sponsor entered into a Sponsor Agreement, pursuant to which, inter alia: (a) each of the Company and HOC appointed JPMorgan Cazenove Limited as sponsor in connection with the applications for Admission; (b) the Company confirmed that it had made all relevant applications to the FSA, the LSE, the Jersey Financial Services Comission, TSX, and CRESTCO, in respect of Admission, and formal approval for this document and for Admission of all the Ordinary Shares and the Exchangeable Shares to the Official List and to the LSE for the Admission of all the Ordinary Shares and the Exchangeable Shares to trading on its main market for listed securities; (c) HOC confirmed that it will make all relevant applications to the FSA, the LSE, the Jersey Financial Services Commission and CRESTCO, in respect of Admission, and formal approval for this document and for Admission of all the Exchangeable Shares to the Official List and to the LSE for the Admission of all the Exchangeable Shares to trading on its main market for listed securities; (d) the Company has agreed to pay the Sponsor a management fee of £1,000,000 plus VAT (if applicable) on Admission; (e) the obligations of the Sponsor are subject to customary conditions (including, amongst other things, Admission occurring). The Sponsor has the right to terminate the Sponsor Agreement prior to the expected date for Admission in certain circumstances that are typical for an

284 agreement of this nature. These circumstances include the occurrence of certain material adverse changes in the condition or the management, business affairs or business prospects of the Company; (f) the Company has agreed to pay (together with any related value added tax) certain costs, charges, fees and expenses, in connection with, or incidental to Admission; and (g) the Company, HOC, and the Directors have given certain warranties and undertakings to the Sponsor and the Company and HOC have on a joint and several basis given certain indemnities to the Sponsor that are typical of an arrangement of this nature. 10.6 Placing Agreement for 2007 Equity Financing On 14 November 2007, HOC completed an equity financing raising 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 that it held, reducing its interest from 52 per cent. to 33.2 per cent. of the issued and outstanding HOC Common Shares. The placing agreement for this financing contains customary warranties and undertakings which were given by HOC and the Directors as to the accuracy of the information contained in the placing agreement and other matters relating to the HOC Common Shares, the Group and its business. 10.7 Underwriting Agreement for the HOC Bond Private Placement In February 2007, HOC raised $165 million by completing a private placement of HOC Bonds. The HOC Bonds were issued at par and have a maturity of 5 years. The coupon and yield to maturity are 8 per cent. annually. HOC Bonds are convertible into HOC Common Shares at a price of $47 per HOC Common Share, and the conversion price is subject to adjustment in certain circumstances. JPMorgan Cazenove acted as sole bookrunner for the issue. The HOC Bonds are in bearer form, serially numbered, in the denomination of $100,000 each with interest coupons attached. The HOC Bonds and interest coupons constitute direct, unsubordinated and unconditional obligations of HOC secured in the manner provided below and ranking pari passu and rateably without any preference among themselves. The obligations of HOC under the HOC Bonds are secured by a first fixed charge over all sums standing in credit to the escrow agreement (being the agreement whereby HOC deposited the sum of $19,836,663 in an escrow account) constituted by a security deed dated 16 February 2007 and made in favour of The Bank of New York, as security trustee, for the benefit of the bondholders. So long as any HOC Bonds remains outstanding: (1) HOC will not make or declare any dividend payment on the HOC Common Shares or make any other distributions to its shareholders nor shall it offer, purchase, redeem or otherwise acquire for consideration any HOC Common Shares, in each case constituting on a consolidated basis more than 30 per cent. of the earnings of HOC for the immediately preceding financial year; (2) the aggregate outstanding principal amount of all indebtedness for borrowed money raised by any person (but excluding any indebtedness for borrowed money raised by one member of the Group from another member of the Group) and benefiting from any security interest given by HOC or any of its subsidiaries upon, or with respect to, or in respect of any company which for the time being holds an interest in, either the Zapadno Chumpasskoye licence or the licence relating to Block 1 and Block 3A, any assets used in the furtherance of the activities permitted by these licences and any revenues derived from these two licences shall not exceed $100,000,000 each; and (3) HOC will ensure that no indebtedness of HOC or any subsidiary and no guarantee by HOC or any subsidiary of any indebtedness of any person will be secured by a security interest upon any of the present or future business, assets or revenues of HOC or its subsidiaries unless HOC or the relevant subsidiary has taken certain required actions. Under the conditions of the HOC Bonds, HOC is required to take (or to procure that there is taken) all necessary action to ensure that immediately upon completion of the Plan of Arrangement, at its option, either (a) the Company is substituted under the bonds as principal debtor in place of HOC or becomes a guarantor under the bonds and, in either case, to make necessary consequential amendments such that the bonds may be converted into or exchanged for Ordinary Shares; or (b) such amendments are made to the bonds such that the bonds may be converted into or exchanged for Ordinary Shares.

285 10.8 Facility Agreements In January 2005, a wholly owned subsidiary of HOC received a sterling denominated loan of £4,500,000 to finance the acquisition of the technical services office at 34 Park Street, Mayfair, London W1K 2JD. Interest on the loan is fixed at 6.515 per cent. for the first five years and then is variable at a rate of LIBOR plus 1.35 per cent. The loan, which is secured on the property, is scheduled to be repaid by 240 instalments of capital and interest at monthly intervals, subject to a residual debt at the end of the term of the loan of no more than £1,860,000. HOC provided a corporate guarantee to the lender. In October 2007, a wholly-owned subsidiary of HOC received a loan of U.S.$9,450,000 to refinance the acquisition of a private corporate jet delivered in 2007. Interest on the loan is variable at a rate of LIBOR plus 1.6 per cent. The loan, which is secured on the aircraft, is scheduled to be repaid by 20 consecutive quarterly instalments of principal. Each instalment equals to US$117,500 with the final instalment being $7,217,500. HOC provided a corporate guarantee to the lender. In November 2007, a bank guarantee for $3,037,500 to cover 50 per cent. of the Group’s share of the Sanjawi work programme in Pakistan was provided by Standard Bank Jersey Limited on behalf of HOGL upon awarding of the Sanjawi licence. The cash-backed bank guarantee has a term until 31 December 2010. In November 2006, a wholly-owned subsidiary of HOC received a loan of $200 million from HOGL for exploration and development purposes in the Zapadno Chumpasskoye field as well as to support the operational and commercial activities of the subsidiary and other activities agreed in advance by the parties. Interest on the loan is variable at a rate of LIBOR plus 4 per cent. The loan is scheduled to be repaid by instalments determined at HOGL’s discretion over a 30 year period. In July 2007, a wholly-owned subsidiary of HOC granted separate charges over its holding of shares in SeaDragon in favour of ABN AMRO and Lloyds TSB Bank plc. These charges were made to support an overdraft facility of $6 million for use by Gander Drilling Limited, a wholly-owned subsidiary of SeaDragon.

11. TAXATION 11.1 Taxation (a) United Kingdom Taxation (i) General The following information is based upon the tax legislation and tax authorities’ practice currently in force in the U.K. and Jersey. The comments are of a general nature only and are not a full description of all relevant tax considerations. The comments only apply to persons who are resident and (in the case of an individual) ordinarily resident in (and only in) the U.K. (except where express reference is made to the treatment of non-U.K. residents) and only apply to persons who hold their Ordinary Shares as investments and are the absolute beneficial owners of them. The information in both the U.K. and Jersey sections below is applicable to such investors and both sections should be read in conjunction with one another. The statements do not constitute advice to any Shareholder. Any person who is in any doubt as to his tax position, or who is subject to tax in a jurisdiction other than the U.K., should consult a professional adviser concerning his tax position in respect of the acquisition, holding or disposal of Ordinary Shares. (ii) Tax Residence The Company is incorporated in Jersey and currently conducts its affairs so that its business is centrally managed and controlled in Guernsey. This summary is prepared on the assumption that its business will continue to be centrally managed and controlled in Guernsey. (iii) Dividends Under current Jersey taxation legislation tax will not be withheld from dividends paid by the Company. Under current U.K. taxation legislation no tax will be withheld from dividends paid by the Company. Currently for U.K. tax purposes no tax credit would attach to any dividends paid by the Company. After 5 April 2008, U.K. tax law is expected

286 to change. Where the Company pays a dividend to a holder of Ordinary Shares being an individual resident in the U.K. (for the purposes of U.K. tax law) that person may be entitled to a tax credit in respect of the dividend received. These provisions are expected to apply to an individual who owns less than 10 per cent. of the Ordinary Shares in the Company provided that that individual receives less than £5,000 in dividends in any tax year from companies which are not resident in the U.K. for tax purposes. The value of the tax credit is currently one ninth of the amount of the dividend received (or 10 per cent. of the aggregate of the amount of the dividend and tax credit). Such an individual will be liable to income tax on an amount equal to the aggregate of the dividend and tax credit (the ‘‘gross dividend’’), which will be regarded as the top slice of his income for tax purposes and will be subject to U.K. income tax at the special dividend rate of tax as described below. Individuals who are not liable to income tax at a rate greater than basic rate (i.e. those who pay tax at the lower or basic rate only) will be liable to tax on the gross dividend at the ‘‘dividend ordinary rate’’ of 10 per cent. This means that the tax credit will satisfy such individual’s liability to pay income tax in respect of the gross dividend and there will be no further tax to pay and no right to claim any repayment of the tax credit from the HMRC. In the case of individuals who are liable to income tax at the higher rate, tax will be payable on dividends at the ‘‘dividend upper rate’’ (currently 32.5 per cent.). The 10 per cent. tax credit will be set against his liability to tax in respect of the gross dividend. Therefore, he will have to pay additional tax equal to 22.5 per cent. of the gross dividend (or 25 per cent. of the net dividend received), to the extent that the gross dividend, when treated as the top slice of his income, falls above the threshold for higher rate income tax. Individual holders of Ordinary Shares who are not liable to income tax in respect of the gross dividend income cannot reclaim payment of the tax credit from HM Revenue and Customs. Subject to certain exceptions, a corporate Shareholder which is resident for tax purposes in the U.K. is not liable to tax on a dividend paid by the Company to it and is not able to claim repayment of the tax credit attaching to the dividend. (iv) Capital Gains Tax A disposal or deemed disposal of capital assets by a U.K. resident or ordinarily resident shareholder will give rise to either a chargeable gain or an allowable loss. Gains and losses are calculated by deducting from the sale proceeds or, in some instances from the market value of the time of disposal, the original cost and incidental costs of acquisition and incidental costs of disposal. Recipients within the charge to corporation tax may be entitled to an indexation allowance in computing a capital gain. Currently, a U.K. resident individual or trustee may be entitled to taper relief in computing a capital gain or loss. It is expected that taper relief will be abolished for disposals after 5 April 2008. U.K. resident individuals or trustees may also be entitled to an annual allowance in arriving at the amount on which they are charged capital gains tax. A disposal or deemed disposal of a capital asset by a U.K. resident or ordinarily resident individual who is not domiciled in the U.K., will be liable to U.K. capital gains tax (‘‘CGT’’) in the same way as for a U.K. domiciled individual unless the asset is situated outside of the U.K. at the time of disposal. Where the asset is non-U.K. situated, gains will only be taxed to the extent that the gains are (or are deemed to be) remitted to the U.K. As the Company is incorporated outside of the U.K., and as its principal register is maintained outside of the U.K. it is expected that the Ordinary Shares will be deemed to be non-U.K. situated for these purposes. Various changes to remittance basis are expected to take place after 5 April 2008. An individual claiming the remittance basis may lose certain tax allowance and, in certain cases, an individual may be charged a flat rate sum of money before the remittance basis can apply. If an individual ceases to be resident or ordinarily resident in the U.K. for a period of less than five years and disposes of the Ordinary Shares, in certain circumstances any gain on that disposal may be liable to U.K. CGT upon that holder becoming once again resident or ordinarily resident in the U.K.

287 (v) Stamp Duty and Stamp Duty Reserve Tax The following comments are intended as a guide to the general United Kingdom stamp duty and stamp duty reserve tax position and do not relate to persons such as market makers, brokers, dealers, intermediaries and persons connected with voluntary arrangements or clearance services, to whom special rules apply. No United Kingdom stamp duty or stamp duty reserve tax will be payable on the issue of Ordinary Shares. Regardless of whether the Ordinary Shares are held in certificated form or uncertificated form, United Kingdom stamp duty (at a rate of 0.5 per cent. of the amount of the value of the consideration for the transfer rounded up to the nearest £5.00) is payable on any instrument of transfer of the Ordinary Shares executed within, or in certain cases brought into, the United Kingdom. Provided that the Ordinary Shares are not registered in any register of the Company kept in the United Kingdom, any agreement to transfer the Ordinary Shares will not be subject to United Kingdom stamp duty reserve tax. (vi) Jersey Taxation (a) Taxation of Company As the Company’s business is centrally managed and controlled in Guernsey, the Company will be regarded as not resident for Jersey tax purposes in Jersey. The Company will not be subject to Jersey income tax on income arising outside of Jersey and by concession, on bank interest arising in Jersey. There is no obligation or entitlement to deduct Jersey income tax from dividends paid on ordinary shares. Jersey is to introduce a goods and service tax (‘‘GST’’) with effect from 1 May 2008. GST is a modern form of sales tax on the domestic consumption of imported and locally produced goods and services, the standard rate of which will be 3 per cent. although some supplies will qualify as zero rated or exemption supplies. The Company will be required to register for GST if its taxable supplies are greater than £300,000. Despite its business being centrally managed and controlled in Guernsey, the Company will conduct its affairs so that it is outside the scope of Guernsey income tax. (b) Tax implications for Jersey resident investor Jersey resident shareholders in receipt of dividends from the Company will be subject to Jersey income tax on those dividends at the standard rate. From 1 January 2009, any Jersey resident investor which, directly or indirectly, owns more than 2 per cent. of the ordinary shares of the Company may be subject to the deemed dividend provisions which seek to tax Jersey resident shareholders on all or a proportion of the Company’s profits in proportion to their shareholding. Under current Jersey law, there are no death or estate duties, capital gains, gift, wealth, inheritance or capital transfer taxes. No stamp duty is levied in Jersey on the transfer inter vivos, exchange or repurchase of Ordinary Shares but there is a stamp duty payable when Jersey Grants of Probate or Letters of Administration are required. Stamp duty is levied according to the size of the estate and in the case of an estate not exceeding £100,000 in value the sum payable would be £50 per £10,000 or part thereof, and for estates above £100,000, £500 on the first £100,000 and £75 per additional £10,000 or part thereof. There is no upper limit on stamp duty payable. An application fee is also due to the registrar of Probate on all Grant applications, this is presently £50. Under Jersey law, a Jersey Grant of Probate or Letters of Administration is required to transfer or redeem shares on the death of a Shareholder except where the total value of the deceased’s Jersey estate is less than £10,000 when the Directors of the Company may, at their discretion, dispense with this requirement on certain conditions being satisfied. If they do so, they may be indemnified against claims under the Probate (Jersey) Law 1998 if the deceased died domiciled within specific British jurisdictions but not for foreign jurisdictions. If you are in any doubt as to your tax position, or are subject to tax in a jurisdiction other than in the U.K., you should consult your professional adviser immediately.

288 As part of an agreement reached in connection with the European Union directive on the taxation of savings income in the form of interest payments, and in line with steps taken by other relevant third countries, Jersey introduced with effect from 1 July 2005 a retention tax system in respect of payments of interest, or other similar income, made to an individual beneficial owner resident in an EU Member State by a paying agent established in Jersey. The retention tax system applies for a transitional period prior to the implementation of a system of automatic communication to EU Member States of information regarding such payments. During this transitional period, such an individual beneficial owner resident in an EU Member State will be entitled to request a paying agent not to retain tax from such payments but instead to apply a system by which the details of such payments are communicated to the tax authorities of the EU Member State in which the beneficial owner is resident. The retention tax system in Jersey is implemented by means of bilateral agreements with each of the EU Member States, the Taxation (Agreements with European Union Member States) (Jersey) Regulations 2005 and Guidance Notes issued by the Policy & Resources Committee of the States of Jersey. Based on these provisions and our understanding of the current practice of the Jersey tax authorities, any dividend distributions to shareholders by the Company and income realised by shareholders upon the sale, refund or redemption of shares do not constitute interest payment for the purpose of the retention tax and therefore neither the Company nor any paying agent appointed by the Company in Jersey is obliged to levy the retention tax in Jersey under those provisions in respect thereof. To the extent that the Company makes distributions in the form of interest in the future, the obligations set out above may apply.

(c) Taxation Implications for a Canadian Resident Investor THIS SUMMARY IS OF A GENERAL NATURE ONLY AND IS NOT INTENDED TO BE, NOR SHOULD IT BE CONSTRUED TO BE, LEGAL, BUSINESS OR TAX ADVICE TO ANY PARTICULAR SHAREHOLDER. CONSEQUENTLY SHAREHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS FOR ADVICE AS TO THE TAX CONSEQUENCES OF AN INVESTMENT IN THE ORDINARY SHARES HAVING REGARD TO THEIR PARTICULAR CIRCUMSTANCES. The following is a summary of the principal Canadian federal income tax considerations under the ITA generally applicable to persons who, for purposes of the ITA, (i) are or are deemed to be resident in Canada, (ii) hold Ordinary Shares as capital property, and (iii) deal at arm’s length with the Company and are not affiliated with the Company (‘‘Canadian Shareholder’’). Ordinary Shares will generally constitute capital property to the holder unless such person holds such securities in the course of carrying on a business, an adventure or concern in the nature of trade or as ‘‘mark to market’’ property for purposes of the ITA. This summary does not apply to a holder (i) that is a ‘‘financial institution’’ or a ‘‘specified financial institution’’, as defined in the ITA, (ii) an interest in which would be a ‘‘tax shelter investment’’, as defined in the ITA, or (iii) in respect to whom the Company is or will be a foreign affiliate within the meaning of the ITA. Such holders and those who do not hold their Ordinary Shares as capital property should consult their own tax advisers regarding their particular circumstances. This summary is based upon the current provisions of the ITA, the regulations thereunder (the ‘‘Regulations’’) and counsel’s understanding of the current published administrative policies and assessing practices of the CRA, all in effect as of the date hereof. This summary also takes into account all proposed amendments to the ITA publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (‘‘Tax Proposals’’), and assumes that all such Tax Proposals will be enacted substantially as proposed. However, no assurances can be given that the Tax Proposals will be enacted in the form proposed, or at all. This summary is not exhaustive of all possible Canadian federal income tax considerations and does not otherwise take into account or anticipate any changes in law, administrative policy or assessing practice, whether by judicial, governmental or legislative action or decision, nor does it take into account provincial, territorial or foreign income tax legislation or considerations, which may differ from the Canadian federal income tax considerations described herein. No

289 advance income tax ruling has been sought or obtained from CRA to confirm the tax consequences of any of the transactions described herein. This summary also assumes that the Company is and will remain a non-resident of Canada for the purposes of the ITA. For the purposes of the ITA, all amounts relating to the acquisition, the holding and the disposition of the Ordinary Shares, including dividends, adjusted cost base and proceeds of disposition must generally be determined in Canadian dollars at applicable exchange rates. (vii) Dividends on Ordinary Shares Dividends received or deemed to be received on Ordinary Shares by a Canadian Shareholder who is an individual will be required to be included in computing the Canadian Shareholder’s income for the purposes of the ITA and will not be subject to the gross up and dividend tax credit rules applicable to dividends received from taxable Canadian corporations under the ITA. Dividends received or deemed to be received on Ordinary Shares by a Canadian Shareholder that is a corporation will be required to be included in computing the Canadian Shareholder’s income for purposes of the ITA and will generally not be deductible in computing its taxable income. (viii) Disposition of Ordinary Shares Cost Averaging of Identical Property The ITA provides for a cost averaging rule for ‘‘identical properties’’, such as shares issued by a company (including any fractional share) that are of the same class or series. Generally, when a person acquires a property that is identical to one or more other properties already held by the person, the person’s adjusted cost base of each identical property will be equal to the quotient obtained when the aggregate of the adjusted cost bases of all the identical properties previously held by the person and the cost of the newly acquired identical property is divided by the number of all such identical properties held at that time. Accordingly, at any time, the cost to a Canadian Shareholder of an Ordinary Share will be averaged with the adjusted cost bases of any other Ordinary Shares held by the Canadian Shareholder as capital property at that time. Acquisition and Disposition of Ordinary Shares A disposition or deemed disposition of Ordinary Shares (including on the purchase of the Ordinary Shares for cancellation by the Company) by a Canadian Shareholder will generally result in a capital gain (or capital loss) to the extent that the proceeds of disposition exceed (or are less than) the aggregate of the adjusted cost base to the Canadian Shareholder of the Ordinary Shares immediately before the disposition and any reasonable cost of disposition. One half of any capital gain (the ‘‘taxable capital gain’’) realised by a Canadian Shareholder will be included in its income for the year of disposition. One half of any capital loss (the ‘‘allowable capital loss’’) realised by a Canadian Shareholder may be deducted by that person against taxable capital gains for the year of disposition subject to and in accordance with rules contained in the ITA. Any excess of allowable capital losses over taxable capital gains for the year of disposition may be deducted in any of the three preceding taxation years or carried forward indefinitely and deducted in any subsequent taxation year against net taxable capital gains realised in such year to the extent and subject to the limitations prescribed in the ITA. Any capital loss resulting from the disposition of Ordinary Shares may, in certain circumstances, be reduced by the amount of dividends previously received or deemed received on Ordinary Shares, to the extent and under the circumstances described in the ITA. Capital gains realised by an individual or trust, other than certain trusts, may give rise to alternative minimum tax under the ITA. (ix) Refundable Tax A Canadian Shareholder that is a ‘‘Canadian controlled private corporation’’ (as such term is defined in the ITA) may be liable to pay a refundable tax on certain investment income, including taxable capital gains and dividends paid on Ordinary Shares.

290 (x) Foreign Property Information Reporting A Canadian Shareholder that is a ‘‘specified Canadian entity’’ for a taxation year or fiscal period and whose total cost amount of ‘‘specified foreign property’’ (which includes the Ordinary Shares) at any time in the year or fiscal period exceeds Cdn$100,000 will be required to file an information return in respect of such property disclosing certain information including particulars of the Canadian Shareholder’s investment in such property. Subject to certain exceptions, a Canadian Shareholder would be a specified Canadian entity. Such Canadian Shareholder holding specified foreign property should consult their tax advisors in this respect. (xi) Proposed Legislation on Foreign Investment Entities On 29 October 2007, Bill C-10 to amend the ITA, including proposals relating to foreign investment entities, was introduced in the House of Commons of Canada (‘‘FIE Legislation’’). The proposed legislation, if enacted, would generally be applicable for taxation years of taxpayers commencing after 2006. Canadian Shareholders should consult their own tax advisors regarding the potential application of these proposed rules in their particular circumstances. (xii) Eligibility for Investment The Ordinary Shares, if and when listed on a designated stock exchange (which would include the LSE), will be qualified investments under the ITA for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans, registered disability savings plans and registered education savings plans.

12. RELATED PARTY TRANSACTIONS Save as disclosed in the financial information in Part VII of this document at Note 24 and elsewhere in this document, no members of the Group entered into related party transactions during the financial year ended 31 December 2006, or during the period between 1 January 2007 and the date of this document.

13. LITIGATION Mr. Micael Gulbenkian, a former chairman and CEO of HOC, who was dismissed on 6 October 2006, has threatened legal action for wrongful dismissal and commenced arbitration procedures. The Group considers the likelihood of any successful claims as remote. As at the date of this document no formal statement of claim has been served on the Group. The Group has, however, received various correspondence from Mr. Gulbenkian’s lawyers stating that Mr. Gulbenkian and his consulting company have or will invoke arbitration procedures based on arbitration clauses contained in agreements with the Group in respect of these allegations. The Directors do not know what the potential outcome of these claims will be and the Group will defend any action. Save as set out in the preceding paragraph, neither the Company nor any member of the Group is or has been involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Company is aware) which may have, or have had during the 12 months prior to the date of this document, a significant effect on the Company and/or the Group’s financial position or profitability. The Directors are not aware of any environmental issues that may affect the Company’s utilisation of its tangible fixed assets.

14. 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.

15. THE CITY CODE The City Code will apply to the Company, and on Admission the Shareholders 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

291 Act, would be available subject to, amongst other things, the offeror acquiring the requisite percentage of the share capital to which the offer relates.

16. CONSENTS 16.1 KPMG LLP U.K. is a member firm of the Institute of Chartered Accountants of England and Wales and has given and not withdrawn its written consent to the inclusion of its reports set out in ‘‘Financial Information’’ in Part VII and in ‘‘Illustrative Projections’’ in Part VIII, in the form and context in which they appear and has authorised the contents of those parts of this document which comprise of its reports for the purposes of Rule 5.5.3R(2)(f) of the Prospectus Rules. 16.2 RPS has given and has not withdrawn its written consent to the inclusion of its report set out in ‘‘Technical Report’’in Part III, in the form and context in which it appears and RPS has authorised those parts of this document which comprise its report, accepted responsibility for its report as part of this document and declared that it has taken all reasonable care to ensure that the information contained in that report is, to the best of its knowledge, in accordance with the facts and contains no omission likely to affect its import.

17. 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 Section B of Part VII 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 completed on 14 November 2007.

18. MISCELLANEOUS 18.1 The auditors of HOC from incorporation to the date of this document have been KPMG LLP Canada, chartered accountants, whose registered national office is Suite 3300, Commerce Court West, 199 Bay Street, Toronto, Ontario M5L 1B2, Canada and of the Company from incorporation to the date of this document have been KPMG LLP U.K., chartered accountants, whose registered address is at 8 Salisbury Square, London EC4Y 8BB. 18.2 The total costs and expenses of, and incidental to, Admission payable by the Company, is estimated to amount to $7 million (= £3.5 million (excluding VAT)). 18.3 The information sourced from third parties has been accurately reproduced and so far as the Company is aware and has been able to ascertain from information published by such third parties (this information is as follows: the online CIA World Factbook (at pages 36, 38 and 44 of Part I of this document) no facts have been omitted which would render the reproduced information inaccurate or misleading. 18.4 The Ordinary Shares are created under the Act and are in registered form with ISIN JE00B2Q4TN56. The Exchangeable Shares are created under the ABCA and are in registered form with ISIN CA42969283053. The Ordinary Shares are in uncertificated form. Computershare acts as the Company’s registrar and transfer agent in Jersey and the U.K. 18.5 None of the Ordinary Shares or Exchangeable Shares have been marketed or are available in whole or in part to the public in conjunction with the applications for the Ordinary Shares and Exchangeable Shares, respectively to be admitted to the Official List. 18.6 No application is currently intended to be made for the Ordinary Shares to be admitted to listing or dealt with on any other exchange other than the London Stock Exchange. Other than the London Stock Exchange, the Exchangeable Shares are also currently intended to be admitted to listing on the TSX. 18.7 There are no arrangements in existence under which future dividends are to be waived or agreed to be waived.

292 19. DOCUMENTS AVAILABLE FOR INSPECTION Copies of the following documents will be available for inspection during normal business hours on any weekday (Saturday, Sundays and public holidays excepted) at the offices of McCarthy Tetrault,´ 2nd Floor, 5 Old Bailey, London EC4M 7BA up to and including 31 March 2009: (a) the Memorandum and Articles of the Company; (b) the audited consolidated accounts of the Group for the nine-month period ended 30 September 2007 and for the three financial years ended 31 December 2004, 31 December 2005 and 31 December 2006; (c) the report from RPS set out in Part III of this document; (d) the reports from KPMG LLP U.K. and KPMG LLP Canada set out in Part VII of this document; (e) the services agreements and terms of appointment for the Directors; (f) the consent letters referred under ‘‘Consents’’ at section 16 above; and (g) this document. Dated 28 March 2008

293 PART XI—DEFINITIONS The following definitions apply throughout this document, except in Part III of this document and Part VII of this document, unless the context otherwise requires: ‘‘ABCA’’ the Business Corporations Act (Alberta), as amended

‘‘Act’’ the Companies (Jersey) Law 1991, and the regulations promulgated thereunder as each may be amended from time to time

‘‘Admission’’ admission of the Ordinary Shares and the Exchangeable Shares to the Official List and to trading on the London Stock Exchange’s main market for listed securities becoming effective

‘‘Aegis’’ Aegis Defence Services Ltd.

‘‘Affiliate’’ has the meaning ascribed to such term in the ABCA

‘‘Afren’’ Afren PCL

‘‘Alberta CallCo’’ 1381890 Alberta ULC, a wholly owned subsidiary of DutchCo incorporated under the laws of Alberta

‘‘Articles’’ the articles of association of the Company

‘‘Articles of HOC’’ the articles of association of HOC, as amended

‘‘Arrangement Agreement’’ the agreement entered into in connection with the Plan of Arrangement between the Company, DutchCo and Alberta CallCo on 22 February 2008 and described in section 1 of Part IX of this document

‘‘Audit Committee’’ the audit committee of the Company

‘‘Beneficiaries’’ the registered holders (other than the Company and its affiliates) of the Exchangeable Shares

‘‘Board’’ or ‘‘Directors’’ the directors of the Company as at the date of this document whose names are set out on page 27 of this document

‘‘BRA’’ Bougainvill Revolutionary Army

‘‘Burren Energy’’ Burren Energy PLC

‘‘Business Day’’ means any day on which commercial banks are generally open for business in Jersey and Calgary, Alberta other than a Saturday, a Sunday or a day observed as a holiday in Jersey or in Calgary, Alberta under the laws of Canada or any jurisdiction therein

‘‘CallCo Redemption Call Right’’ means the right, but not the obligation,

(a) notwithstanding the right of the holders of Exchangeable Shares to require HOC to redeem any or all of their Exchangeable Shares for Ordinary Shares, to purchase Exchangeable Shares that are the subject of a Retraction Request for an amount per Exchangeable Share (the ‘‘Redemption Call Purchase Price’’) equal to the Current Market Price of an Ordinary Share on the last Business Day prior to the Retraction Date which shall be satisfied in full by CallCo causing to be delivered to such holder on Ordinary Share, plus to the extend not paid, an additional amount equivalent to the full amount of all

294 declared and unpaid dividends on each such Exchangeable Share held by such holder on any dividend record date which occurred prior to the Retraction Date;

(b) notwithstanding the right of holders of Exchangeable Shares to redeem all of the outstanding Exchangeable Shares pursuant to the articles of the Exchangeable Shares, to purchase all but not less than all of the Exchangeable Shares then outstanding in connection with a proposed redemption by HOC for the Redemption Call Purchase Price on the Redemption Date, which shall be satisfied in full by CallCo causing to be delivered to such holder on Ordinary Share, plus to the extent not paid, an additional amount equivalent to the full amount of all declared and unpaid dividends on each such Exchangeable Share held by such holder on any dividend and unpaid dividends on each such Exchangeable Share held by such holder on any dividend record date which occurred prior to the Redemption Date, provided that, notwithstanding any other provision of the Plan of Arrangement, the Exchangeable Shares that are subject to a Retraction Request may not be purchased by CallCo if such Exchangeable Shares are held by or on behalf of a Person in the United States or a U.S. Person

‘‘Canadian Dollar Equivalent’’ means, in respect of an amount expressed in a currency other than Canadian dollars (the ‘‘Foreign Currency Amount’’) at any date, the product obtained by multiplying (a) the Foreign Currency Amount by (b) the noon spot exchange rate on such date for such foreign currency expressed in Canadian dollars as reported by the Bank of Canada or, in the event such spot exchange rate is not available, such exchange rate on such date for such foreign currency expressed in Canadian dollars as may be deemed by the board of directors of the Company to be appropriate for such purpose

‘‘Canadian GAAP’’ Canadian generally accepted accounting principles

‘‘Canadian National National Instrument 51-101 Oil & Gas Disclosure Standards of Instrument 51-101’’ the Canadian Securities Administrators

‘‘Canadian person’’ any individual who is a resident of Canada or any Company, partnership or other entity created or organised in or under the laws of Canada and any estate or trust the income of which is subject to Canadian federal income taxation regardless of its source

‘‘City Code’’ the City Code on Takeovers and Mergers issued by the Panel on Takeovers and Mergers

‘‘CND’’ ChumpassNefteDobycha

‘‘Coatbridge’’ Coatbridge Estates Limited

‘‘Code of Conduct’’ the code of business conduct and ethics of the Company

‘‘Combined Code’’ the Combined Code on Corporate Governance published in June 2006 by the Financial Reporting Council being the key source of corporate governance recommendations for companies listed on the Official List

295 ‘‘Companies Act’’ the U.K. Companies Act 1985, as amended

‘‘Company’’ Heritage Oil Limited a company incorporated in Jersey on 6 February 2008 with Company number 99922 and whose registered address is Ordnance House, 31 Pier Road, St Helier, Jersey JE4 8PW Channel Islands

‘‘Company Control Transaction’’ means any merger, amalgamation, tender offer, take-over bid, scheme of arrangement, material sale of shares (including a material sale of the shares of CallCo held by DutchCo) or rights or interests therein or thereto or similar transactions involving the Company, or any proposal to do so that upon completion, does or would materially affect control of the Company

‘‘Company Dividend Declaration means the date on which the board of directors of the Company Date’’ declares any dividend on the Ordinary Shares

‘‘Computershare’’ Computershare Investor Services (Channel Islands) Limited

‘‘Computershare Canada’’ means Computershare Trust Company of Canada

‘‘Congo’’ the Republic of Congo

‘‘Corporate Governance Committee’’ the corporate governance committee of the Company

‘‘CREST’’ the computerised settlement system operated by CRESTCo Limited to facilitate the transfer of title to shares in uncertificated form

‘‘CRESTCO’’ Euroclear U.K. and Ireland Limited

‘‘Court Hearing’’ the Alberta provincial court hearing to be held in connection with the Plan of Arrangement

‘‘Court Meeting’’ the meeting of the shareholders of the HOC Common Shares to be convened in accordance with Plan of Arrangement

‘‘Current Market Price’’ means, in respect of an Ordinary Share on any date, the Canadian Dollar Equivalent of the average closing prices of the Ordinary Shares during a period of 20 consecutive trading days ending not more than three trading days before such date on the LSE or, if the Ordinary Shares are not then listed on the LSE, on such stock exchange or automated quotation system on which the Ordinary Shares are listed or quoted, as the case may be, as may be selected by the board of directors of the Company for such purpose; provided, however, that if in the opinion of the board of directors of the Company the public distribution or trading activity of the Ordinary Shares during such period does not create a market which reflects the fair market value of the Ordinary Shares then the Current Market Price of the Ordinary Shares shall be determined by the board of directors of the Company, in good faith and in its sole discretion, and provided further that any such selection, opinion or determination by the board of directors of the Company shall be conclusive and binding

‘‘DRC’’ the Democratic Republic of Congo

‘‘DRC PSC’’ the production sharing contract entered into between the government of the DRC and the Group in July 2006 in respect of the exploration and development work on Blocks 1 and 2

296 ‘‘DTR’’ the Disclosure and Transparency Rules published by the FSA from time to time

‘‘DutchCo’’ Heritage Oil Cooperatief¨ U.A., a wholly owned subsidiary of the Company incorporated under the laws of the Netherlands

‘‘ECOMOG’’ Economic Community of West African States Monitoring Group

‘‘ECOWAS’’ Economic Community of West Africa States

‘‘EU’’ the European Union

‘‘E&E’’ exploration and evaluation costs

‘‘Eagle’’ Eagle Energy (Oman) Limited

‘‘Eagle Drill’’ Eagle Drill Limited

‘‘Effective Date’’ date upon which the Plan of Arrangement becomes effective upon the filing of the Articles of HOC

‘‘Effective Date’’ means the date shown on the certificate issued pursuant to section 193(11) of the ABCA

‘‘Exchangeable Right’’ the right, upon HOC facing certain insolvency events, to require the Company to purchase from each Beneficiary all or any part of the Exchangeable Shares held by the Beneficiary

‘‘Exchangeable Shareholders’’ the registered holders of Exchangeable Shares

‘‘Exchangeable Shares’’ the exchangeable shares of HOC the terms of which are set out at Part IX of this document

‘‘Exchangeable Share Voting Event’’ means any matter in respect of which holders of Exchangeable Shares are entitled to vote as holders of Exchangeable Shares, other than an Exempt Exchangeable Share Voting Event, and, for greater certainty, excluding any matter in respect of which holders of Exchangeable Shares are entitled to vote (or instruct the Trustee to vote) in their capacity as Beneficiaries under (and as that term is defined in) the Voting and Exchange Trust Agreement

‘‘Exempt Exchangeable Share Voting means any matter in respect of which holders of Exchangeable Event’’ Shares are entitled to vote as holders of Exchangeable Shares in order to approve or disapprove, as applicable, any change to, or in the rights of the holders of, the Exchangeable Shares, where the approval or disapproval, as applicable, of such change would be required to maintain the economic equivalence of the Exchangeable Shares and the Ordinary Shares

‘‘Extraordinary General Meeting’’ or the extraordinary general meeting of HOC that was held on ‘‘EGM’’ 20 March 2008 in connection with the Plan of Arrangement

‘‘FSA’’ or ‘‘Financial Services the Financial Services Authority in its capacity as the competent Authority’’ authority for the purposes of Part VI of FSMA and in the exercise of its functions in respect of admission to the Official List otherwise than in accordance with Part VI of FSMA

‘‘FSMA’’ the Financial Services and Markets Act 2000 of England and Wales, as amended

‘‘Gazprom’’ JSC Gazprom

297 ‘‘Governmental Entity’’ means any:

(a) federal, provincial, state, territorial, regional, municipal, local or other government, governmental or public department, court, tribunal, arbitral body, commission, board or agency having jurisdiction over the Company or HOC as applicable;

(b) any subdivision, agent, commission, board or authority of any of the foregoing; or

(c) any quasi governmental or private body exercising any regulatory, expropriatory or taxing authority under or for the account of any of the foregoing

‘‘Group’’ the Company and its subsidiary companies set out in section 3 of Part X of this document

‘‘Heritage Austria’’ Heritage Oil & Gas (Austria) GesmbH

‘‘Heritage Barbados’’ Heritage Oil (Barbados) Limited

‘‘Heritage DRC’’ Heritage DRC Limited

‘‘Heritage Holdings’’ Heritage Oil & Gas Holdings Limited

‘‘Heritage International Holding’’ Heritage International Holding GesmbH

‘‘Heritage Middle East’’ Heritage Energy Middle East Limited

‘‘Heritage Security holders’’ holders of HOC Common Shares and holders of HOC Options

‘‘Heritage Switzerland’’ Heritage Oil & Gas (Switzerland) SA

‘‘HOC’’ or ‘‘Corporation’’ Heritage Oil Corporation, a company incorporated under the laws of Alberta whose shares are expected to be owned by DutchCo (a wholly owned subsidiary of the Company) and the Exchangeable Shareholders immediately following the completion of the HOC Subscription

‘‘HOC Board of Directors’’ means the board of directors of HOC

‘‘HOC Bonds’’ the issued and outstanding convertible bonds in HOC dated 16 February 2007

‘‘HOC Common Shares’’ the common shares of HOC, the terms of which are set out at Part IX of this document

‘‘HOC Option’’ an issued and outstanding option to acquire HOC Common Shares pursuant to the HOC Stock Option Plan

‘‘HOC Plan’’ or ‘‘HOC Stock Option the stock option plan of HOC approved by HOC Shareholders Plan’’ in 2004 and the new stock option plan approved by HOC Shareholders in 2007

‘‘HOGL’’ Heritage Oil & Gas Limited

‘‘holder’’ means, when used in reference to the Exchangeable Shares, the holders of Exchangeable Shares from time to time in the register maintained by and on behalf of HOC in respect of the Exchangeable Shares

‘‘IFRS’’ International Financial Reporting Standards

298 ‘‘ISIN’’ International Security Identification Number

‘‘ITA’’ Income Taxes Act (Canada)

‘‘KRI’’ the Kurdistan Region of Iraq

‘‘KRG’’ the Kurdistan Regional Government

‘‘LIBOR’’ London Interbank Offered Rate

‘‘Liquidation Call Right’’ means the overriding right given to CallCo, in the event of and notwithstanding the proposed liquidation, dissolution or winding-up of HOC or any other distribution of the assets of HOC among its shareholders for the purpose of winding up its affairs pursuant to the articles of HOC dealing with the Exchangeable Shares, to purchase from all but not less than all of the holders of Exchangeable Shares (other than the Company or any holder of Exchangeable Shares which is an Affiliate of the Company) on the effective date of such liquidation, dissolution, winding-up or other distribution (the ‘‘Heritage Liquidation Date’’) all but not less than all of the Exchangeable Shares held by such holders on payment by CallCo of an amount per Exchangeable Share (the ‘‘Liquidate Call Purchase Price’’) equal to the Current Market Price of Ordinary Shares on the last Business Day prior to the Heritage Liquidation Date which shall be satisfied in full by CallCo causing to be delivered to such holder, one Ordinary Share; plus, to the extent not paid by HOC, an additional amount equivalent to the full amount of all declared and unpaid dividends on each such Exchangeable Share on any dividend record date which occurred prior to the Heritage Liquidation Date. In the event of the exercise of the Liquidation Call Right by CallCo, each holder shall be obligated to sell all the Exchangeable Shares held by the holder to CallCo on the Heritage Liquidation Date on payment by CallCo to the holder of the Liquidation Call Purchase Price for each such share. and HOC shall have no obligation to pay the Heritage Liquidation Amount to the holders of such Exchangeable Shares or otherwise redeem such shares so purchased by CallCo

‘‘Listing Rules’’ the listing rules of the Financial Services Authority

‘‘London Stock Exchange’’ or ‘‘LSE’’ London Stock Exchange plc

‘‘Major Shareholder’’ Albion Energy Limited, a company incorporated under the laws of the Commonwealth of Barbados

‘‘Maurel et Prom’’ Etablissements Maurel et Prom

‘‘Memorandum’’ the memorandum of association of the Company

‘‘Naturalay Technologies’’ Naturalay Technologies Limited

‘‘New Companies Act’’ the U.K. Companies Act 2006, as amended

‘‘Normal Course Issuer Bid’’ the action of a Canadian incorporated Company buying back its own outstanding shares from the markets so it may cancel them

‘‘NGK’’ Neftyanaya Geologicheskaya Kompaniya

‘‘Official List’’ the Official List of the Financial Services Authority

‘‘Oman’’ the Sultanate of Oman

299 ‘‘Option’’ an option to acquire Ordinary Shares pursuant to the Scheme

‘‘Ordinary Shares’’ ordinary shares of no par value in the capital of the Company

‘‘PNG’’ Papua New Guinea

‘‘Pakistan’’ the Islamic Republic of Pakistan

‘‘Participating Canadian the shareholders of HOC who have elected to receive Shareholders’’ Exchangeable Shares in return for their shareholding in HOC in connection with the Plan of Arrangement

‘‘Person’’ includes an individual, sole proprietorship, partnership, unincorporated association, unincorporated syndicate, unincorporated organization, trust, body corporate, a natural person in his capacity as trustee, executor, administrator, or other legal representative and a Governmental Entity or any agency or instrumentality thereof

‘‘Pipelay’’ Natural Pipelay Worldwide Limited

‘‘Plan of Arrangement’’ the court approved reorganisation of the share capital of HOC, pursuant to Article 193 of the ABCA where all of the existing HOC Common Shares were converted to Ordinary Shares and Exchangeable Shares

‘‘PRMS’’ SPE/WPC/AAPG/SPEE 2007 Petroleum Resource Management System

‘‘Prospectus Directive’’ EU Prospectus Directive (2003/71/EC)

‘‘Prospectus Rules’’ the rules made for the purposes of Part VI of FSMA in relation to offers of securities to the public and admission of securities to trading on a regulated market

‘‘PSC’’ or PSA’’ production sharing contract or production sharing agreement

‘‘RAK Petroleum’’ RAK Petroleum PCL

‘‘Ranger’’ Ranger Oil Limited

‘‘Redemption Date’’ means the date, if any, established by the HOC Board of Directors for the redemption by HOC of all but not less than all of the outstanding Exchangeable Shares pursuant to the Articles of HOC, which date shall be no earlier than the seventh anniversary of the Effective Date, unless:

(a) there are fewer than 10 per cent. of the number of Exchangeable Shares issued on the Effective Date outstanding (other than Exchangeable Shares held by the Company and its Affiliates and as such number of shares may be adjusted as deemed appropriate by the HOC board of directors to give effect to any subdivision or consolidation of or stock dividend on the Exchangeable Shares, any issue or distribution of rights to acquire Exchangeable Shares or securities exchangeable for or convertible into Exchangeable Shares, any issue or distribution of other securities or rights or evidences of indebtedness or assets, or any other capital reorganisation or other transaction affecting the Exchangeable Shares), in which case the HOC board of directors may accelerate such redemption date to such date prior to the seventh

300 anniversary of the Effective Date as they may determine, upon at least 60 days’ prior written notice to the registered holders of the Exchangeable Shares;

(b) a Company Control Transaction occurs, in which case, provided that the HOC board of directors determines in good faith in its sole discretion that it is not reasonably practicable to substantially replicate the terms and conditions of the Exchangeable Shares in connection with such Company Control Transaction and that the redemption of all but not less than all of the outstanding Exchangeable Shares is necessary to enable the completion of such Company Control Transaction in accordance with its terms, the HOC board of directors may accelerate such redemption date to such date prior to the seventh anniversary of the Effective Date as they may determine, upon such number of days prior written notice to the registered holders of the Exchangeable Shares as the HOC board of directors may determine to be reasonably practicable in such circumstances;

(c) an Exchangeable Share Voting Event is proposed, in which case, provided that the HOC board of directors determines, in good faith and in its sole discretion, that it is not reasonably practicable to accomplish the business purpose intended by the Exchangeable Share Voting Event (which business purpose must be bona fide and not for the primary purpose of causing the occurrence of a Redemption Date), in any other commercially reasonable manner that does not result in an Exchangeable Share Voting Event, the redemption date shall be the Business Day prior to the record date for any meeting of the holders of the Exchangeable Shares to consider the Exchangeable Share Voting Event and the HOC board of directors shall give such number of days’ prior written notice of such redemption to the registered holders of the Exchangeable Shares as the HOC board of directors may determine to be reasonably practicable in such circumstances; or

(d) an Exempt Exchangeable Share Voting Event is proposed and the holders of the Exchangeable Shares fail to take the necessary action at a meeting of holders of Exchangeable Shares, to approve or disapprove, as applicable, the Exempt Exchangeable Share Voting Event, in which case the redemption date shall be the Business Day following the day of such meeting on which the holders of the Exchangeable Shares failed to take such action and the HOC board of directors shall give such number of days’ prior written notice of such redemption to the registered holders of the Exchangeable Shares as the HOC board of directors may determine to be reasonably practicable in such circumstances,

provided, however, that the accidental failure or omission to give any notice of redemption under clauses (a), (b), (c) or (d) above to the holders of Exchangeable Shares shall not affect the validity of any such redemption.

‘‘Regulations’’ Companies (Uncertificated Securities) (Jersey) Order 1999

301 ‘‘Relationship Agreement’’ means an agreement entered into between the Company, Anthony Buckingham and the Major Shareholder dated 28 March 2008 described in section 10.4 of Part X of this document;

‘‘Remuneration Committee’’ the remuneration committee of the Company

‘‘Replacement Stock Option Scheme’’ the Company’s stock option scheme dated 18 March 2008 or ‘‘Scheme’’

‘‘Reporting Accountants’’ in respect of matters relating to the United Kingdom and Jersey, KPMG LLP U.K., and in respect of matters relating to Canada, KPMG LLP Canada

‘‘Responsible Persons’’ the Company and the Directors

‘‘Reserves Data’’ the proved, probable and possible reserves volumes and related estimated future net revenue values attributable to the Company as evaluated by RPS and based on reserves information supplied by the Company to RPS

‘‘Retraction Request’’ request by a holder of Exchangeable Shares for redemption of such Exchangeable Shares

‘‘RUF’’ Revolutionary United Front

‘‘ROWAL’’ Ranger Oil West Africa Limited

‘‘RPS’’ RPS Energy

‘‘RPS Report’’ or ‘‘Technical Report’’ the mineral experts report setting out the Group’s statement of reserves data and other oil and gas information effective 30 September 2007, prepared in accordance with PRMS and reproduced in its entirety at Part III of this document

‘‘SEC’’ the U.S. Securities and Exchange Commission

‘‘SEDAR’’ the Canadian System for Electronic Document Analysis and Retrieval

‘‘Seadragon’’ SeaDragon Offshore Limited

‘‘Securities Act’’ the United States Securities Act of 1933, as amended

‘‘Senior Manager’’ the manager of the Company whose name is set out in section 1 of Part II of this document

‘‘Shareholders’’ holders of Ordinary Shares or the holder of the Special Voting Share from time to time

‘‘Sonangol’’ Sociedad Nacional de Combust´ıveis de Angola — Sonangol, U.E.E.

‘‘Special Voting Share’’ the Special Voting Share in the Company to be issued to the Trustee

‘‘Sponsor’’ JPMorgan Cazenove Limited, in its capacity as sponsor to the Company

‘‘Sponsor Agreement’’ the agreement entered into on 28 March 2008 between the Directors, the Company, the Sponsor and HOC described in section 10.5 of Part X of this document

302 ‘‘Support Agreement’’ the agreement entered into on 17 March 2008 between the Company, DutchCo, Alberta CallCo and HOC described in section 10.3 of Part X of this document

‘‘Transfer Agent’’ means Computershare Trust Company of Canada or such other person as may from time to time be appointed by HOC as the registrar and transfer agent for the Exchangeable Shares

‘‘Trustee’’ means Computershare Canada and, subject to the provisions of Article 9 of the Voting and Exchange Trust Agreement, includes any successor trustee

‘‘TNK-BP’’ Tyumenskaia Neftanaia Companiya

‘‘TSX’’ the Toronto Stock Exchange

‘‘Tullow’’ Tullow Oil PLC

‘‘Uganda’’ the Republic of Uganda

‘‘U.K.’’ or ‘‘United Kingdom’’ the United Kingdom of Great Britain and Northern Ireland

‘‘UNITA’’ National Union for the Total Independence of Angola

‘‘U.S.’’ or ‘‘United States’’ the United States of America, its territories and possessions, any state of the United States of America and the District of Columbia and all other areas subject to its jurisdiction

‘‘U.S. Person’’ has the meaning ascribed to such term in Regulation S of the Securities Act, as amended

‘‘Voting and Exchange Trust’’ an agreement entered into among the Company, HOC, Alberta CallCo and the Trustee substantially in the form of Schedule 4 to the Arrangement Agreement

‘‘Voting and Exchange Trust a voting and exchange trust agreement entered into by the Agreement’’ Company, HOC Alberta CallCo and the Trustee, on 27 February 2008, the terms of which are set out in section 10.2 of Part X of this document

‘‘Voting Rights’’ the right to receive notice of, attend (in person or by proxy or by corporate representative), speak (in person or by corporate representative) and to cast (in person or by proxy or by corporate representative) one vote per share on a poll vote, or one vote per Shareholder on a show of hands, at general meetings of the Company, whether available to a Shareholder by virtue of a holding of Ordinary Shares or the Special Voting Share

‘‘C$’’ or ‘‘Canadian Dollars’’ or the lawful currency of Canada ‘‘Cdn’’

‘‘£’’ or ‘‘Pounds Sterling’’ the lawful currency of the U.K.

‘‘$’’, ‘‘U.S.$’’ ‘‘US$’’ or ‘‘Dollars’’ the lawful currency of the U.S.

‘‘Chf’’ or ‘‘Swiss Franc’’ the lawful currency of Switzerland

‘‘RR’’ or ‘‘Russian Rouble’’ the lawful currency of Russia

303 PART XII—GLOSSARY The following definitions apply throughout this document, unless the context otherwise requires: ‘‘API’’ a specific gravity scale developed by the American Petroleum Institute for measuring the relative density of various petroleum liquids, expressed in degrees

‘‘bbl’’ barrel

‘‘bbls’’ barrels

‘‘bbls/d’’ or ‘‘bopd’’ barrels per day

‘‘Bcf’’ billion cubic feet

‘‘boe’’ barrels of oil equivalent(1)

‘‘boe/d’’ or ‘‘boepd’’ barrels of oil equivalent per day

‘‘condensate’’ low density, high API hydrocarbon liquids that are present in natural gas fields where it condensates out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas

‘‘Gj’’ gigajoules

‘‘LPG’’ liquid petroleum gas

‘‘m3’’ cubic metres

‘‘Mbbls’’ thousand barrels

‘‘MMbbls’’ million barrels

‘‘Mboe’’ thousands of barrels of oil equivalent

‘‘MMboe’’ millions of barrels of oil equivalent

‘‘Mcf’’ thousand cubic feet

‘‘Mcf/d’’ thousand cubic feet per day

‘‘MMBtu’’ million British thermal units

‘‘MMcf’’ million cubic feet

‘‘MMcf/d’’ million cubic feet per day

‘‘MMstb’’ million stock tank barrels

‘‘NGLs’’ natural gas liquids

‘‘Petroleum’’ any mineral, oil or relative hydrocarbon (including condensate and natural gas liquids) and natural gas existing in its natural condition in strata (but not including coal or bituminous shale or other stratified deposits from which oil can be extracted by destructive distillation)

‘‘Possible Reserves’’ those additional reserves that are less certain to be recovered than Probable Reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible Reserves

‘‘Probable Reserves’’ those additional reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual

304 remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves

‘‘Proved Reserves’’ those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves

‘‘psi’’ pounds per square inch

‘‘psia’’ pounds per square inch absolute

‘‘SPE’’ Society of Petroleum Engineers

‘‘WPC’’ World Petroleum Council

‘‘WTI’’ West Texas Intermediate

Note (1): Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

CONVERSION The following table sets forth standard conversions from Standard Imperial Units to the International System of Units (or metric units).

To Convert From To Multiply By boes Mcfs 6 Mcf m3 28.174 m3 Cubic feet 35.494 bbls m3 0.159 m3 bbls oil 6.290 Feet Metres 0.305 Metres Feet 3.281 Miles Kilometres 1.609 Kilometres Miles 0.621 Acres Hectares 0.405 Hectares (Saskatchewan) Acres 2.471 Hectares (Alberta) Acres 2.500

305