Prospectus re Admission to the Official List - Heritage Oil

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 inthis document. To the best of the knowledge and belief of the Company and the Directors (who have taken all reasonable care to ensure thatsuch is the case), the information contained in this document is in accordance with the facts and contains no omission likely to affectits import.Application has been made to the Financial Services Authority for all of the Ordinary Shares and Exchangeable Shares to be admitted tolisting on the Official List and to the London Stock Exchange plc for such Ordinary Shares and Exchangeable Shares to be admitted totrading on the London Stock Exchange’s main market for listed securities. Admission to the Official List together with admission to trading onthe London Stock Exchange’s main market for listed securities (together ‘‘Admission’’) will constitute admission to listing on a regulatedmarket. It is expected that Admission will become effective and that unconditional dealings on the London Stock Exchange will commencein 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 orExchangeable 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 Listand to trading on the London Stock ExchangeSponsorJPMorgan CazenoveExpected share capital immediately following AdmissionAuthorisedIssued and Fully PaidUnlimited Ordinary Shares of no par value 250,513,0321 Special Voting Share of no par value 1Unlimited 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 (GeneralProvisions) (Jersey) Order 2002, and the registrar has given, and has not withdrawn, consent to its circulation. The Jersey Financial ServicesCommission (the ‘‘Commission’’) has given, and has not withdrawn, its consent under Article 2 of the Control of Borrowing (Jersey) Order1958 (the ‘‘Order’’), to the issue of the Ordinary Shares and the Special Voting Share by the Company. The Commission has given, and hasnot withdrawn, its consent under Article 4 of the Order to the issue by the Company of any securities exchangeable into Ordinary Shares ofthe Company. The Commission has given, and has not withdrawn, its consent to HOC under Article 8 of the Order to the circulation inJersey of this document. It must be clearly understood that, in giving these consents, neither the Jersey registrar of companies nor theCommission takes any responsibility for the financial soundness of the Company or for the correctness of any statements made, or opinionsexpressed, with regard to it. The Commission is protected by the Control of Borrowing (Jersey) Law 1947, as amended, against any liabilityarising 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 onbehalf of the Company or HOC is intended to constitute, or should be construed as, advice on the merits of the subscription for, OrdinaryShares 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 ServicesAuthority, 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 itscustomers 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 thepossession or distribution of this document (or any other offering or publicity materials or application form(s) relating to the OrdinaryShares or the Exchangeable Shares) in any jurisdiction, other than the United Kingdom and Jersey, where action for that purpose may berequired. Accordingly, neither this document, nor any advertisement or any other offering material may be distributed or published in anyjurisdiction except under the circumstances that will result in compliance with any applicable laws and regulations. Persons into whosepossession this document comes should inform themselves about and observe any such restrictions. Any failure to comply with theserestrictions 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 makeany representations other than those contained in this document and, if given or made, such information or representations must not berelied 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 Grouptaken as a whole since, or that the information contained herein is correct as of any time subsequent to, the date of this document, save forsuch 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 regimeestablished thereunder, JPMorgan Cazenove accepts no responsibility whatsoever for the contents of this document or for any otherstatement made or purported to be made by it or on its behalf in connection with the Company, HOC, the Ordinary Shares, theExchangeable Shares or Admission. JPMorgan Cazenove accordingly disclaims all and any liability whether arising in tort or contract orotherwise (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 itsown solicitor, financial adviser or tax adviser for legal, financial and/or tax advice in relation to the subscription or purchase of OrdinaryShares 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.

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

SUMMARY INFORMATIONThis summary must be read as an introduction to this document. The following summary information has beenprepared in accordance with the Prospectus Rules and provides summary information on the Ordinary Sharesand the Exchangeable Shares and on the risks of investment therein. Any decision to invest in the Company orHOC should be based upon consideration of this document as a whole by the investor and not justthe summary.Following the implementation of the relevant provisions of the Prospectus Directive (Directive 2003/71/EC) ineach Member State of the European Economic Area, no civil liability will attach to those persons responsible forthis 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 MemberState of the European Economic Area, the plaintiff may, under the national legislation of the Member Statewhere the claim is brought, be required to bear the costs of translating this document before legal proceedingsare initiated.1. INFORMATION ON THE GROUPThe Company was incorporated in Jersey on 6 February 2008 to be the ultimate holding company of theGroup. The Group was established in 1992 (with HOC being incorporated on 30 October 1996) andcommenced trading in the mid-1990s as an independent upstream exploration and production groupengaged in the exploration for, and the development, production and acquisition of, oil and gas in its coreareas of Africa, the Middle East and Russia. The Group has exploration projects in Uganda, the KRI, theDRC, Malta, Pakistan and Mali, and producing properties in Oman and Russia. HOC, being a member ofthe Group and in anticipation of Admission, has proposed a reorganisation of its share capital. Thereorganisation will culminate in the creation of the Exchangeable Shares which will be subject to votingrights and terms and conditions different from the Ordinary Shares but which, subject to certainconditions, will be exchangeable for Ordinary Shares on a one-to-one basis. HOC intends (at orimmediately following Admission) to procure the admission of the Exchangeable Shares to listing on boththe TSX and on the Official List together with admission to trading on the London Stock Exchange’s mainmarket for listed securities.The Group’s management team believes that it has demonstrated a track-record of finding new substantialdiscoveries, particularly in Africa, including the hydrocarbon system in the Albert Basin, Uganda and theM’Boundi oilfield in Congo. The Group’s producing, development and exploration projects, together withpotential opportunities, provide a combination of early cash flow and longer term value creationopportunities for its shareholders.2. SUMMARY OF GROUP RESERVES AND RESOURCESRPS has certified that as of 30 September 2007, the Group’s net working interest reserves and value, usingmoney of the day prices, discounted at 10 per cent., were as follows:Net NetWorking Entitlement NetInterest Reserves PresentReserves Number ValueMMboe MMboe $ MillionsProved ............................................... 25.5 24.2 30.3Probable Additional ..................................... 40.3 37.9 229.3Total Proved Probable ................................. 65.8 62.1 259.6Total Proved Probable Possible ......................... 171.5 163.9 824.1RPS has certified that the Group had a 50 per cent. working interest share of the mean risked workinginterest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at30 September 2007. The Government of Uganda has a back-in right which could, if exercised, reduce theGroup’s working interest to 42.5 per cent.1

3. GROUP COMPETITIVE STRENGTHS AND COMPETITIVE ADVANTAGESThe 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 containsignificant quantities of oil; it has demonstrated its first-mover advantage in acquiring assets in territories such as Uganda and inrecent 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 ofCdn$181.5 million completed in November 2007.4. STRATEGYThe 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 strategicguidelines in its business activities to achieve this, in particular:acquiring and investing in oil and gas properties throughout the world, with a particular emphasis onAfrica, the Middle East and Russia; andleveraging off a highly effective network of influential industry, political and institutionalrelationships, enabling it to gain access to a wide variety of new oil and gas business opportunities togenerate future growth for the Group.5. SUMMARY FINANCIAL INFORMATIONThe tables below set out the Group’s summary financial information for the periods indicated. The datahas been extracted without material adjustment from the historical financial information relating to HOCin Part VII of this document. The Group will report under IFRS and so this financial information has beenprepared and presented in accordance with IFRS for the nine-month period ended and as at30 September 2007 (with unaudited comparative financial information for the nine-month period endedand as at 30 September 2006), for the year ended and as at 31 December 2006 and for the year ended andas at 31 December 2005. In addition, financial information has been presented in accordance with theprevious basis of reporting (Canadian GAAP) for the year ended and as at 31 December 2005 and for theyear 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 thekey or summarised financial information.Note 28 to the historical financial information in relation to HOC, explanation of transition to IFRS, inPart VII of this document explains the effect of the change of the basis of reporting from Canadian GAAPto IFRS.2

Summary Consolidated Income Statements (for the nine-month period ended 30 September 2007 andfinancial years 2005 and 2006 prepared in accordance with IFRS and audited and for the nine-monthperiod ended 30 September 2006 prepared in accordance with IFRS and unaudited)Year endedNine-month periods31 December ended 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Net revenue .......................... 1,184,125 6,834,239 5,475,430 2,843,053Net expenses .......................... (12,795,257) (19,689,292) (12,646,009) (41,150,721)Gain on disposal of subsidiaries ............ — — — 1,077,132Finance income (costs) .................. (161,534) (27,961,892) (7,764,647) (30,251,946)Income from and gain on disposal ofdiscontinued operations ................ 3,510,441 12,449,190 2,417,316 —Net loss for the period attributable to equityholders of the Corporation .............. (8,262,225) (28,367,755) (12,517,910) (67,482,482)Net earnings per share from discontinuedoperationsBasic and diluted ....................... 0.16 0.57 0.11 —Net loss per share from continuing operationsBasic and diluted ....................... (0.54) (1.86) (0.68) (3.02)Net loss per shareBasic and diluted ....................... (0.38) (1.29) (0.57) (3.02)3

Summary Consolidated Balance Sheets (at 30 September 2007 and 31 December 2005 and 2006prepared in accordance with IFRS and audited and at 30 September 2006 prepared in accordance withIFRS and unaudited)31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)AssetsNon-current assetsAssets held for sale — — 16,962,091 —Intangible exploration assets ............... 43,503,704 54,767,332 45,602,140 85,746,870Intangible development costs .............. 1,187,371 1,574,039 1,346,858 —Property, plant and equipment ............. 25,282,552 32,187,098 25,546,939 59,105,312Other financial assets .................... — 914,558 — 4,200,90969,973,627 89,443,027 89,458,028 149,053,091Current assetsAssets held for sale ..................... — — 425,412 —Inventories ........................... 251,915 98,921 211,510 79,768Prepaid expenses ....................... 219,222 531,273 515,899 340,402Trade and other receivables ............... 1,318,450 9,839,506 664,953 6,455,303Cash and cash equivalents ................ 8,583,321 46,861,146 46,851,571 61,894,71110,372,908 57,330,846 48,669,345 68,770,18480,346,535 146,773,873 138,127,373 217,823,275LiabilitiesCurrent liabilitiesTrade and other payables ................. 4,438,649 12,715,381 9,396,651 15,781,606Borrowings ........................... 248,045 147,720 140,352 160,224Liabilities of disposal group held for sale ..... — — 807,208 —4,686,694 12,863,101 10,344,211 15,941,830Non-current liabilitiesBorrowings ........................... 7,520,438 63,124,843 62,512,234 144,918,765Derivative financial liability ............... — 27,997,140 8,621,068 32,810,103Provisions ............................ 434,849 62,322 — 133,274Liabilities of disposal group held for sale ..... — — 419,770 —7,955,287 91,184,305 71,553,072 177,862,14212,641,981 104,047,406 81,897,283 193,803,97267,704,554 42,726,467 56,230,090 24,019,303Shareholders’ Equity Attributable to EquityHolders of the CorporationShare capital .......................... 22,854,418 24,580,984 23,508,025 40,910,098Reserves ............................. 973,956 2,637,058 1,363,795 35,083,262Retained earnings (deficit) ................ 43,876,180 15,508,425 31,358,270 (51,974,057)67,704,554 42,726,467 56,230,090 24,019,3034

Summary Consolidated Cash Flow Statements (for the nine-month period ended 30 September 2007and financial years 2005 and 2006 prepared in accordance with IFRS and audited and for the ninemonthperiod ended 30 September 2006 prepared in accordance with IFRS and unaudited)Year endedNine-month periods31 December ended 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Cash used in operating activities ............ (7,854,323) (12,737,451) (8,331,393) (7,212,661)Cash used in investing activities ............ (11,946,720) (28,823,833) (12,074,902) (53,535,576)Cash provided by financing activities ......... 9,020,147 58,031,186 57,356,469 75,080,072Cash provided by discontinued operations ..... 4,313,817 21,324,969 1,009,595 —(Decrease) increase in cash and cashequivalents .......................... (6,467,079) 37,794,871 37,959,769 14,331,835Cash and cash equivalents—beginning of period 16,235,523 8,583,321 8,583,321 46,861,146Foreign exchange (loss) gain on cash held inforeign currency ...................... (1,185,123) 482,954 308,481 701,730Cash and cash equivalents—end of period ..... 8,583,321 46,861,146 46,851,571 61,894,711Summary Consolidated Income Statements (for financial years 2004 and 2005 prepared in accordancewith Canadian GAAP and audited)2004 2005$ $Net revenue ............................................... 6,596,982 8,013,722Net 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 52,434,857Other ................................................... 41,677 (740,879)Retained earnings, end of year ................................. 52,434,857 47,894,165Net 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 withCanadian GAAP and audited)Assets2004 2005$ $Current AssetsCash and cash equivalents .................................... 16,235,523 8,583,321Accounts receivable ......................................... 4,640,802 1,318,450Note receivable ............................................ 4,280,161 —Inventories ............................................... 94,483 216,474Prepaid expenses ........................................... 272,168 219,22225,523,137 10,337,467Property and equipment ....................................... 54,083,097 72,382,935Deferred development costs .................................... 1,013,012 1,187,37180,619,246 83,907,773Liability and Shareholders’ EquityCurrent LiabilitiesAccounts payable and accrued liabilities .......................... 6,397,247 4,438,649Current portion of long-term debt .............................. — 248,0456,397,247 4,686,694Long-term debt ............................................. — 7,520,438Asset retirement obligations .................................... 328,553 434,849Shareholders’ Equity:Share capital and warrants .................................... 21,434,168 22,854,418Contributed surplus ......................................... 24,421 517,209Retained earnings .......................................... 52,434,857 47,894,16573,893,446 71,265,79280,619,246 83,907,773Summary Consolidated Cashflow Statements (for financial years 2005 and 2004 prepared inaccordance with Canadian GAAP and audited)2004 2005$ $Cash provided by operating activities ............................. 1,866,009 697,123Cash used in investing activities ................................ (11,310,312) (16,184,349)Cash provided by financing activities ............................. 604,953 9,020,147Foreign 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 16,235,523Cash and cash equivalents, end of year ........................... 16,235,523 8,583,3216. CURRENT TRADING AND PROSPECTSThe Company is well positioned to benefit from a series of exploration, appraisal and development drillingprogrammes in 2008. Drilling programmes in Blocks 3A and 1 are scheduled to commence in Uganda in2008. An exploration well is also scheduled to commence drilling in the Miran licence in the KRI in thesecond half of 2008.6

Production from the Zapadno Chumpasskoye field in Western Siberia should increase from the average of342 bopd in February 2008 as a result of existing wells being brought on production as well as furtherdevelopment drilling.Production from Block 8, Oman is not expected to change materially from the average net production of109 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 FACTORSPrior to investing in the Ordinary Shares or the Exchangeable Shares, prospective investors shouldconsider 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, theGroup’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 thedate of this document; issuance of debt to finance acquisitions would increase the Group’s debt levels and there can be noassurance that the Group will be able to meet its obligations in respect of additional debt facilitiesafter 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 andgas production; and7

adverse media or other public speculation about the Chief Executive Officer’s past associations couldmaterially adversely affect the Group’s reputation and the market price of the Ordinary Shares and/orthe 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, physicalor 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 entityor 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 ofcompanies incorporated in other jurisdictions; and there may be difficulty in enforcing against the Group’s assets any judgments obtained inJersey 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 ofthe 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 theShareholders of the Company; there are potential conflicts of interest to which the directors, the senior manager and principalShareholders 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 theOrdinary 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 equityrights offering; and Jersey law limits the circumstances under which shareholders of companies may bring derivativeactions.8. REASONS FOR THE PLAN OF ARRANGEMENT AND LONDON LISTINGThe Directors believe that the reorganisation of the Group in a tax efficient manner in accordance with theterms of the Arrangement Agreement and the admission of the Ordinary Shares and the ExchangeableShares to the Official List of the FSA and to trading on the main market of the LSE is in the best interestsof the Group and holders of securities in HOC.8

Given the geographic spread of the Group’s production, development and exploration licences with a corefocus on Africa, the Middle East and Russia, the Directors believe that it would now be more appropriatefor the Group to be based in Europe, where a substantial number of holders of securities in HOC and mostof the management of the Group reside.The Directors believe that admission to the main market of the LSE will raise the Group’s profile andstatus amongst European investors and within the oil and gas sector generally, and will give the Companyaccess 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 assistin 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 businessdays 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 participatingin the Plan of Arrangement such shareholders have been offered Exchangeable Shares as an alternative toexchanging their HOC Common Shares for Ordinary Shares on the effective date of the Plan ofArrangement. The TSX has conditionally approved the listing of the Exchangeable Shares on the TSXsubject to the receipt of final documentation.Each HOC Common Share will be exchanged for either ten Ordinary Shares or ten Exchangeable Sharesas part of the Plan of Arrangement to help increase the liquidity, following Admission, of the OrdinaryShares and the Exchangeable Shares in addition to providing a suitable initial trading price of shares onthe LSE.At a future date after 12 months from the date of this document, in order to finance the remainder of theoperation expenditures required to bring the initiated oil and gas exploration activities of the Group intofull production the Group is likely to require additional equity and/or debt financing or the sale of noncoreassets. For the purposes of the ‘‘Illustrative Projections of the Group’’ contained in Part VIII of thisdocument, this additional funding is assumed to be equity finance.9. DIVIDEND POLICYEach 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 cashresources for the operation and development of its business.10. SIGNIFICANT CHANGEThere has been no significant change in the financial or trading position of the Group since30 September 2007, the date to which the historical financial information in Part VII(B) of this documenthas been prepared, save for an equity financing, raising gross proceeds of Cdn $181.5 million from theissue of 3 million HOC Common Shares, which closed on 14 November 2007.11. WORKING CAPITALThe 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 CODEThe City Code will apply to the Company and, on Admission, the shareholders of the Company will beafforded the protections provided by the City Code, in particular the mandatory takeover provisions inrule 9 of the City Code. In the event of a takeover, the squeeze-out provisions in articles 117 to 119 of theAct would be available subject to, amongst other things, the offeror acquiring the requisite percentage ofthe share capital to which the offer relates.13. CAPITALISATION AND INDEBTEDNESSThe Group’s capitalisation as at 31 December 2007 was $260.3 million and its net funds were $38.5 million.9

14. MAJOR SHAREHOLDEROn Admission, the Major Shareholder and Mr. Anthony Buckingham, a Director and the Chief ExecutiveOfficer of the Company and HOC, will own and control in aggregate 84,540,340 Ordinary Sharesrepresenting approximately 33.2 per cent. of the aggregate voting rights in the share capital of theCompany. The Major Shareholder and Mr. Anthony Buckingham entered into a relationship agreementwith the Company on 28 March 2008. The purpose of this agreement is to ensure that transactions andrelationships between the Group, the Major Shareholder and Mr. Anthony Buckingham are at arm’slength and on normal commercial terms.15. DIRECTORS AND SENIOR MANAGEMENTOn Admission, the members of the Board and their ages and positions will be:Name Age PositionMichael Hibberd ......................... 52 Chairman and Non-Executive DirectorAnthony Buckingham ...................... 56 Chief Executive OfficerPaul Atherton ........................... 42 Chief Financial OfficerGregory Turnbull ......................... 53 Non-Executive DirectorJohn McLeod ........................... 61 Non-Executive DirectorGeneral Sir Michael Wilkes ................. 67 Non-Executive DirectorOn Admission, in addition to the Board, the position of the Senior Manager will be:Name Age PositionBrian Smith ............................. 55 VP Exploration16. COMBINED CODEThe Directors support high standards of corporate governance. The Company currently complies with allaspects of the Combined Code except for the recommendation that at least half of the board of directorsshould be determined to be independent and except for the recommendation in the Smith Guidance onthe Combined Code that the Chairman of the Company should not be appointed to the Company’s AuditCommittee. As at Admission, only two of the six directors (excluding the Chairman) are considered by theBoard to be independent. However, as soon as is reasonably practicable, the Directors intend to rectify thisdeficiency in its full compliance with the Combined Code.10

RISK FACTORSAny investment in the Ordinary Shares or Exchangeable Shares is subject to a number of risks. Before makingany decision to invest in the Ordinary Shares or Exchangeable Shares, prospective investors should carefullyconsider all the information contained in this document including, in particular, the specific risks describedbelow. Some of the following factors relate principally to the Group’s business and the sector in which itoperates. Other factors relate principally to an investment in the Ordinary Shares or Exchangeable Shares. Therisks and uncertainties described below are not intended to be exhaustive and are not the only ones facing theGroup. Additional risks and uncertainties not currently known to the Directors, or that they currently deemimmaterial, may also have an adverse effect on the Group’s business, financial condition, results of operationsand prospects. If this occurs, the price of the Ordinary Shares and/or Exchangeable Shares may decline andinvestors could lose all or part of their investment. Investors should consider carefully whether an investment inthe Ordinary Shares or Exchangeable Shares is suitable for them in light of the information in this documentand their own personal circumstances.Risks Relating to the Group’s OperationsRecovery and Reserve and Resource Estimates May Prove IncorrectUnless stated otherwise, the reserves and resources data contained in this document are taken from theRPS Report, which has been prepared in accordance with the standards established by the PRMS. Thereserves and resources data and the associated estimated future net cash flow from the Group’s propertiescontained 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 cashflows to be derived therefrom, including many factors that are beyond the control of the Group. Estimatingthe amount of reserves and resources is a subjective process and, in addition, results of drilling, testing andproduction 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 shouldnot be construed as representing exact quantities. These estimates and evaluations include a number ofassumptions relating to factors such as initial production rates, production decline rates, ultimate recoveryof reserves, timing and amount of capital expenditures, marketability of production, future prices of oil andgas, operating costs and royalties and other government levies that may be imposed over the producing lifeof the reserves. These assumptions were based on price forecasts in use at the date the relevant evaluationswere prepared and many of these assumptions are subject to change and are beyond the control of theGroup. 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 successof exploitation activities intended to be undertaken in future years. The reserves and estimated cash flowsto be derived therefrom contained in such evaluations will be reduced to the extent that such exploitationactivities 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 shouldnot be placed on the forward-looking statements contained herein by investors (including in datacontained within the RPS Report or extracted or derived from the RPS Report and whether expressed tobe 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, certaincategories of reserves and resources (such as prospective or contingent resources) are inherently lesscertain 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 tobe incorrect, the Group may be unable to recover and produce the estimated levels or quality of oil or gasand the Group’s business, prospects, financial condition or results of operations could be materially andadversely affected.Exploration Activities are Capital Intensive and Involve a High Degree of RiskOil and gas exploration activities are capital intensive and involve a high degree of risk. There is noassurance that expenditures made on future exploration by the Group will result in new discoveries of oilor gas in commercial quantities. It is difficult to estimate the costs of implementing any exploratory drillingprogramme due to the inherent uncertainties of drilling in unknown formations, the costs associated withencountering various drilling conditions such as over-pressured zones, tools lost in the hole and changes indrilling plans and locations as a result of prior exploratory wells or additional seismic data andinterpretations thereof. If exploration activities prove unsuccessful over a prolonged period of time, the11

Group may not, after twelve months from the date of this document, have sufficient working capital tocontinue to meet its obligations and its ability to obtain additional financing necessary to continueoperations may also be adversely affected.Future Appraisal of Potential Oil and Gas Properties May Involve Unprofitable EffortsThe Group’s future appraisals of potential oil and gas properties may involve unprofitable efforts, not onlyfrom dry wells, but from wells that are productive but do not produce sufficient net revenues to return aprofit after drilling, operating and other costs and expenses. Completion of a well does not assure a profiton 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 fieldoperating conditions may also adversely affect the production from successful wells including delays inobtaining governmental approvals, permits, licences, authorisations or consents, shut-ins of connectedwells resulting from extreme weather conditions, insufficient storage or transportation capacity or othergeological and mechanical conditions. While close well supervision and effective maintenance operationscan contribute to maximising production rates over time, production delays and declines from normal fieldoperating conditions cannot be eliminated. Any such productions, delays and declines could be expected toadversely affect revenue and cash flow levels.Whether the Group ultimately undertakes an exploration or development project depends upon a numberof factors, including availability of and cost of capital, current and projected oil and gas prices, receipt ofgovernment approvals, access to the relevant property, the costs and availability of drilling rigs and otherequipment, supplies and personnel necessary to conduct operations at the property, success or failure ofsimilar activities in similar areas and changes in the expected levels of capital expenditure to completethe project.The Group continues to gather data about its new venture opportunities and new projects on an ongoingbasis. Additional information may cause the Group at any time to alter its project schedule or determinethat a new venture opportunity or project should not be pursued, which could adversely affect the Group’sbusiness and prospects.Under certain of the Group’s PSCs and concession agreements, the Group is obliged to financeexploration, development and operations of the relevant property, and the related facilities and equipmentand will only recover its costs if there is successful production in accordance with the terms of the PSCsand agreements. However, there can be no assurance that the Group will discover commercial quantities ofoil or gas at such operations. Accordingly, there can be no assurance that the Group will recover its initialoutlay of capital expenditure and operating costs at any such operation, and in such event the Group’sbusiness, financial condition, results of operations and prospects could be materially and adverselyaffected.Oil and Gas Prices FluctuateThe Group’s results of operations and financial condition are significantly affected by prevailing prices ofoil 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 oiland 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 levelsof 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 noassurance that existing prices for oil and gas will be maintained in the future. Any material decline in suchprices could result in a reduction of the Group’s net production revenue and a decrease in the valuation ofthe Group’s exploration, appraisal and development properties. The economics of producing from some12

wells may change as a result of lower prices, which could result in a reduction in the volumes produced bythe Group. The Group might also elect not to produce from certain wells at lower prices. All of thesefactors could result in a material decrease in the Group’s net production revenue and the financialresources available to it to make planned capital expenditure. This would have a material adverse effect onthe 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 gasproduction 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 benefitfrom 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 notcurrently entered into any hedging instruments at the present time, if it were to do so in the future it couldalso be subject to margin requirements associated with these instruments. Because the Group is notcurrently hedging it is currently exposed to fluctuations in oil and gas prices which could materially affectthe Group’s financial condition, business, prospects and results of operations.Without the Addition of Reserves through Exploration, Acquisition or Development Activities, the Group’sReserves and Production will Decline Over Time as Reserves are ExploitedThe Group’s future oil and gas reserves, production and cash flows to be derived therefrom are highlydependent on the Group’s success in exploiting its current reserve base and acquiring or discoveringadditional reserves. Without the addition of reserves through exploration, acquisition or developmentactivities, the Group’s reserves and production will decline over time as reserves are exploited. A futureincrease in the Group’s reserves will depend not only on the Group’s ability to develop its presentproperties, but also on its ability to select and acquire suitable producing properties or prospects. There isno assurance that the Group’s future exploration and development efforts will result in the discovery anddevelopment of additional commercial accumulations of oil and gas. If such efforts are unsuccessful, theGroup’s total reserves may not increase or may decline, which could have a material adverse effect on theGroup’s business, financial condition, prospects and results of operations.Production Operations Involve Many Inherent RisksProduction operations of the Group or by operators of assets in which the Group has an interest involverisks 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 orunexpected rock formations, abnormal pressures, cratering and sulphur gas releases. Offshore operationsof the Group may also be subject to natural disasters as well as to hazards inherent in marine operationsand damage to pipelines and subsea facilities from trawlers, anchors and vessels. The occurrence of any ofthese events could result in environmental damage, injury to persons and loss of life, a failure to produceoil or gas in commercial quantities or an inability to fully produce discovered reserves. Consequentproduction delays and declines from normal field operating conditions can be expected to adversely affectrevenue and cash flow levels to varying degrees. Oil and gas production operations are also subject to allthe risks typically associated with such operations, including premature decline of reservoirs and theinvasion of water into producing formations.The Group’s production is currently sourced from its interests in a limited number of PSCs or concessionsagreements. Should the Group encounter any problems in any one PSC or concession, it could have amaterial adverse impact upon the Group’s planned levels of production.Interruptions in Availability of Exploration, Production or Supply InfrastructureOil and gas exploration and development activities are dependent on the availability of drilling and relatedequipment in the particular areas where such activities will be conducted. Current high demand for suchlimited equipment or access restrictions is affecting the availability and cost of such equipment to theGroup and operators or production facilities in which the Group has an interest and from time to timedelays exploration and development activities. Such interruptions or delays in the availability ofinfrastructure, including drilling rigs in particular and pipelines and storage tanks, on which explorationand 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 ScarceThe Group contracts or leases services and capital equipment from third party providers. Such equipmentand services can be scarce and may not be readily available at times and places required. In addition, costsof third party services and equipment have increased significantly over recent years and may continue torise. Scarcity of equipment and services and increased prices may in particular result from any significantincrease in exploration and development activities on a region by region basis which might be driven byhigh demand for oil and gas. In the regions in which the Group operates there is significant demand forcapital equipment and services. The unavailability and high costs of such services and equipment couldresult in a delay or restriction in the Group’s projects and adversely affect the feasibility and profitability ofsuch projects and therefore have an adverse affect on the Group’s business, financial condition, results ofoperations and prospects.Reliance on other Operators and Stakeholders Limits the Group’s Control Over Certain ActivitiesTo the extent the Group is not the operator of its oil and gas properties, including in Oman where RAKPetroleum is the operator and in the DRC where Tullow is the operator, it will be dependent on suchoperators for the timing of activities related to such properties and will be largely unable to direct orcontrol the activities of the operators or the costs of production and exploration of such operations. Inaddition, the success of the Group will be largely dependent upon the performance of the operator’s keyemployees. Any mismanagement of an oil or gas property by the operator may result in delays or increasedcosts to the Group’s non-operated exploration, development and production activities, which couldmaterially and adversely affect the Group’s business, financial condition, results of operationsand prospects.The terms of any relevant operating agreement generally impose standards and requirements in relation tothe operator’s activities. While the Group has deliberately acquired interests in oil and gas properties thatare operated by operators it believes to be reputable, there can be no assurance that any such operator willobserve such standards or requirements.There is a risk that other parties with interests in the Group’s oil and gas properties may elect not toparticipate in certain activities relating to those properties and which require that party’s consent. In thesecircumstances, it may not be possible for such activities to be undertaken by the Group alone or inconjunction 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 obligationsto fund capital or other funding obligations in relation to such properties. In such circumstances, theGroup may be required under the terms of the relevant operating agreement to contribute all or part ofany such funding shortfall.After the twelve month period from the date of this document, any such delay or inability to undertakesuch activities, increased cost or obligation to provide further funding could adversely affect the Group’sbusiness, financial condition, results of operations and prospects.Permits, Approvals, Authorisations, Consents and Licences May Be Difficult to Obtain, Sustain or RenewThe operations of the Group require licences, approvals, authorisations, consents and permits and in somecases renewals of existing licences, approvals, authorisations, consents and permits from variousgovernmental authorities. The Directors believe that the Group currently holds or has applied for allnecessary licences, approvals, authorisations, consents and permits to carry on the activities which it iscurrently conducting under applicable laws and regulations in respect of its properties, and also believethat 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, sustainor renew such licences, approvals, authorisations, consents and permits on acceptable terms are subject tochanges 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 notobtained or maintained, the Group may be curtailed or prohibited from proceeding with plannedexploration or development of oil and gas properties.Amendments to current laws, regulations and permits, authorisations, licences, consents and approvalsgoverning 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 productionfrom producing properties or require abandonment or delays in development of new properties, all of14

which could have a materially adverse effect on the Group’s business, financial condition, prospects andresults of operations.Regulatory Requirements can be Onerous and ExpensiveThe current or future operations of the Group, including development activities and commencement ofproduction on its properties, require permits, authorisations, licences, consents and approvals from variousforeign, federal, state and local governmental authorities and such operations are and will be governed byapplicable laws and regulations governing oil and gas exploration and development, exports, taxes, labourstandards, occupational health, waste disposal, toxic substances, land use, environmental protection andother matters.Any changes or requirements additional to any such applicable laws, regulations and permittingrequirements may require the installation of additional equipment or remedial actions in order to ensurecompliance with such amendments, which may be expensive.Failure to comply with applicable laws, regulations and permitting requirements may result in enforcementactions in local jurisdictions thereunder, including orders issued by regulatory or judicial authoritiescausing operations to cease or be curtailed, and may include corrective measures requiring capitalexpenditures, installation of additional equipment or remedial actions.Parties engaged in oil and gas operations may be required to compensate those suffering loss or damage byreason of such activities and may have civil or criminal fines or penalties imposed for violations ofapplicable laws or regulations.The Group Cannot Completely Protect Itself Against Title DisputesIn many of the countries in which the Group operates, land title systems are not developed to the extentfound in many industrialised countries and there may be no concept of registered title. Although theGroup believes that it has good title to its oil and gas properties, it cannot control or completely protectitself against the risk of title disputes or challenges. There can be no assurance that claims or challenges bythird 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 PSCsigned with the KRG (without the prior approval of the Iraqi government) is considered to be void by theIraqi government as they have stated it violates the ‘‘prevailing Iraqi law’’. On the basis of KRI legaladvice, 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 OilCorporation of Libya, dated 28 February 2008, stating that the Block 7 licence area offshore Malta lieswithin the Libyan continental shelf and a portion of this area has already been licensed to Sirte OilCompany. This letter also demands that the Group refrain from any activities over or concerning theBlock 7 licence area and asserts the Libyan government’s right to seek to invoke Libyan and internationallaw to protect its rights in the Block 7 licence area. The Directors believe that the Libyan government’sclaims are unfounded.In addition, the DRC work programme pursuant to the DRC PSC cannot be commenced prior to the grantof a presidential decree from the DRC government. The validity of the award of the DRC licences to whichthe work programme relates is currently being disputed by the Congolese Oil Ministry; this is beingrigorously defended by the Group and its partner. There can be no assurance that final approval orratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscal terms will not bere-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 thatrelevant governments will not revoke, or significantly alter the conditions of, the applicable exploration anddevelopment authorisations, licences, permits, approvals and consents and that such exploration anddevelopment authorisations, licences, permits, approvals and consents will not be challenged or impugnedby third parties. There is no certainty that existing rights or additional rights applied for will be granted orrenewed on terms satisfactory to the Group.The Group is Highly Dependent on its Executive ManagementThe Group is highly dependent upon its executive management and the loss of such executive managementcould have a materially adverse effect on the Group. In particular, the Chief Executive Officer of theCompany and HOC, Mr. Anthony Buckingham, has a number of key relationships that are important to15

the Group’s business and existing oil and gas properties. The Group does not have any key-man insurancepolicies, and therefore there is a risk that the unexpected loss of services of any member of executivemanagement (through serious injury, death or resignation) could have a materially adverse effect on theGroup. In addition, in assessing any risk associated with an investment in the Ordinary Shares orExchangeable Shares, it should be recognised that any investor would be relying on the ability and integrityof the existing management of the Company.The Group’s preparation of its consolidated IFRS financial information can be a technical task and isdependent on key accounting personnelThe preparation of the Group’s consolidated IFRS financial information is a fairly complex task requiringIFRS-experienced accounting personnel and involving the recording of complicated and non-routinetransactions that are technical in nature. There is an increasing demand for a limited number ofIFRS-experienced accounting personnel who also have knowledge of Canadian GAAP as more Canadiancompanies 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 financialinformation according to Canadian GAAP and applied Canadian corporate practice and financialreporting procedures to the Group such that there can be no guarantee that the Group will not facedifficulties in preparing consolidated IFRS financial information or applying its new U.K. financialreporting procedures in all circumstances in the future. Any of the above factors could materially adverselyaffect 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 inrelation to recording items in its financial statements and the nature of its financial reporting proceduresand notwithstanding the above, the Directors believe that the Group’s financial systems, which have beenreviewed by its professional advisers, are sufficient to ensure compliance with the requirements of theDTR as a listed entity.Environmental Liabilities Can Be SignificantSignificant liability could be imposed on the Group for damages, clean-up costs or penalties in the event ofcertain discharges into the environment, environmental damage caused by previous owners of propertypurchased by the Group, acts of sabotage or non-compliance with environmental laws or regulations by theGroup. Such liabilities could have a materially adverse effect on the Group. It is not possible to predictwhat future environmental regulations will be enacted or how current or future environmental regulationswill be applied or enforced in the future. The Group may have to incur significant expenditure for theinstallation and operation of systems and equipment for remedial measures in the event thatenvironmental regulations become more stringent or governmental authorities choose to enforce themmore 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 notresult in a curtailment of production or a material increase in the cost of production, development orexploration activities or otherwise adversely affect the Group’s business, financial condition, results ofoperations or prospects.As a party to various PSCs and concession agreements, members of the Group may have undertakenobligations to restore production areas to standards acceptable to the relevant state authorities at the endof the production fields’ commercial lives. Parties to such PSCs are typically liable for their share of anydecommissioning work. Any obligation to decommission a production facility may involve a substantialexpenditure. These decommissioning costs are necessarily incurred at a time when the related productionfacilities are no longer generating revenue and no provisioning has been made in the Group’s accounts forsuch future decommissioning costs. It is intended that the decommissioning costs, when they arise, will beborne by the Group out of production revenue. There can, however, be no assurance that the productionrevenue will be sufficient to meet these decommissioning costs as and when they arise, and if the Grouphas to apply other or additional financial resources to meet these costs instead, it could have a materiallyadverse 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 DocumentAt 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 noassurance that the Group will be successful in obtaining required financing on acceptable terms at therelevant time or at all. The location of the Group’s oil and gas properties in developing countries maymake 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 suchproperties, 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 notsufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt orequity financing will be available to meet these requirements and this will have a materially adverse effecton 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 Fromthe Date of this DocumentAlthough the Group has sufficient working capital to meet its present requirements, being for the periodwhich is twelve months after the date of publication of this document, the Group’s ability thereafter togenerate sufficient operating cash flow to make scheduled payments on its indebtedness and meet othercapital requirements will depend on its future operating and financial performance. The Group’s futureperformance will be impacted by a range of economic, competitive and business factors that it cannotcontrol, such as general economic and financial conditions in its industry, including fluctuations inprevailing oil and gas prices, or the economy generally.A significant reduction in operating cash flows resulting from changes in economic conditions, increasedcompetition, or other challenges identified as risk factors in this document could increase the need foradditional financings or alternative sources of liquidity and could have a material adverse effect on theGroup’s business, financial condition, results of operations, prospects and its ability to service its debt andother obligations. If the Group is unable to service its indebtedness in the future, it will be forced to adoptan alternative strategy that may include actions such as selling assets, restructuring or refinancing itsindebtedness, seeking additional equity capital or reducing capital expenditures. Furthermore, the Groupmay not be able to effect any of these alternative strategies on satisfactory terms, if at all, or they may notyield sufficient funds to make required payments on its indebtedness.Issuance of Debt to Finance Acquisitions Would Increase the Group’s Debt LevelsFrom time to time, the Group may enter into transactions to acquire assets or the shares of othercorporations. These transactions may be financed partially or wholly with debt, which may increase theGroup’s debt levels above industry standards. After twelve months from the date of this document, therecan be no assurance that the Group will at any time be able to meet its obligations in respect of suchadditional debt facilities and any actions taken by counterparties in relation to default may have a materialadverse effect on the Group’s business, prospects, liquidity, financial condition, cash flows and resultsof operations.After twelve months from the date of this document, the level of the Group’s indebtedness from time totime could impair its ability to obtain additional financing in the future on a timely basis to take advantageof business opportunities that may arise and limit the Group’s operational flexibility.Significant Competition Attracting and Retaining Skilled PersonnelAttracting and retaining additional skilled personnel will be required to ensure expansion of the Group’sbusiness. The Group faces significant competition for skilled personnel in the oil and gas sector. Skilledpersonnel are required in the areas of exploration and development, operations, engineering, businessdevelopment, oil and gas marketing, finance and accounting. There is no assurance that the Group willsuccessfully attract new personnel or retain existing personnel required to continue to expand its businessand to successfully execute and implement its business strategy.The International Oil and Gas Industry is Highly Competitive in all its PhasesThe international oil and gas industry is highly competitive in all its phases. Competition is particularlyintense in the acquisition of prospective oil and gas properties, exploration and production licences, and oiland gas reserves. The Group’s competitive position depends on its geological, geophysical and engineeringexpertise, its financial resources, and its ability to develop its properties on time and on budget and itsability to select, acquire and develop proved reserves and on its ability to foster and maintain relationshipswith governments of the countries in which it operates. The Group competes with numerous otherparticipants in the search for oil and gas, the acquisition of oil and gas properties on time and on budgetand in the marketing of oil and gas. The Group’s competitors include oil and gas companies which havegreater financial resources, more local contacts, staff and facilities than the Group. Many such competitorsnot only explore for and produce hydrocarbons, but also carry on refining and marketing of oil and gas and17

other products on a world-wide basis. Additionally, companies not previously investing in oil and gas oroperating in that sector may choose to acquire reserves to establish a firm supply or simply as aninvestment. Such companies will also provide competition for the Group. The Group’s ability to increasereserves in the future will depend not only on its ability to develop its present properties, but also on itsability 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 andreliability of delivery. The Group competes with major and independent oil and gas companies and otherindustries supplying energy and fuel in the marketing and sale of oil and gas to transporters, distributorsand end-users, including industrial, commercial and individual consumers.Due Diligence of Assets and Acquisition Targets is Inherently IncompleteThe Group’s strategy includes increasing its oil and gas reserves through acquisitions of interests in furtheroil and gas properties. Although the Group performs a review of the companies, businesses and propertiesit acquires (or intends to acquire) to standards consistent with industry practices, such reviews areinherently incomplete. It generally is not feasible to review in-depth every individual property involved ineach acquisition. The Group will commonly focus its due diligence efforts on higher value properties andwill simply review the lower value interests on a sample basis. However, even in-depth due diligencereviews may not reveal existing or potential problems, nor will they permit the acquirer to becomesufficiently 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, suchas ground water contamination, are not always observable or evident when a due diligence review is carriedout. On that basis, the Group may, in making any acquisition, assume liabilities in relation to the relevantasset, including environmental liabilities. There can be no assurance that any acquisition by the Group willbe successful in whole or in part.Future Acquisitions May Involve Many Common Acquisition RisksRisks commonly associated with acquisitions of companies, businesses or properties include the difficultyof integrating operations and personnel in relation to any such business or property, problems withminority shareholders if the transactions are structured as the acquisition of companies, the potentialdisruption of the Group’s own business, the diversion of management’s time and resources from theexisting Group business, and the possibility that indemnification agreements with sellers may beunenforceable 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 mayactually be less than the amount it pays for it or its estimated production capacity or potential may belower than expected.Managing the Group’s Expected Growth and Development Could Be ChallengingThe Group has experienced significant growth and development over a short period of time and expects tocontinue 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 ofnew personnel and continued access to funds to finance this growth. Failure to successfully manage theGroup’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 DelayThe Group has entered into agreements with a number of contractual counterparties in relation to the saleand supply of its oil and gas production volumes. Accordingly, the Group is subject to the risk ofcounterparty default or delayed or withheld payments.In certain areas in which the Group operates, its selection of counterparties may be constrained eitherlegally or as a result of geographic, infrastructure or other constraints or factors. All of the Group’sproduction in the last five years has been derived from the Congo, Oman and Russia. In 2006 and 2007, theGroup sold all of its production, in each country, to a single customer for each commodity. Substantially allof the Group’s accounts receivables from oil and gas sales were from three credit-worthy customers anddebtors 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 competitorsfor the transmission or purchase of oil and gas produced by the Group may expose it to disadvantageous18

contractual or pricing terms, both of which could adversely affect the Group’s business, results ofoperations, financial condition and prospects.Insurance May Not be Sufficient to Cover Full Extent of LiabilitiesThe Group’s involvement in the exploration for and development of oil and gas properties may result inthe 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 orother 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 jointventure partners, such indemnities may be difficult to enforce given the financial positions of those givingthe 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 suchas the cost of the policies, industry standard practice and the risks associated with the exploration anddevelopment of oil and gas properties in the countries in which it operates. The Group does not maintainkey-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 suchliabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances theGroup may elect not to obtain insurance to deal with specific risks due to the high premiums associatedwith such insurance or for other reasons. The payment of such uninsured liabilities would reduce the fundsavailable to the Group. The occurrence of a significant event that the Group is not fully insured against, orthe insolvency of the insurer of such event, could have a material adverse effect on the Group’s financialposition, business, results of operations or prospects.Currency Fluctuations and Foreign Exchange Particularly in Relation to United States DollarsThe Group’s current capital expenditures, exploration commitments, revenues and cost base aredenominated 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, theGroup’s revenue margins and capital expenditures may be materially affected. Expenses in Russian roublesare partially offset by income earned in Russian roubles. The developing countries in which the Groupoperates or proposes to operate impose or may impose foreign exchange restrictions that may materiallyaffect 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 andGas ProductionThe Group may be required to hire and train local workers in its oil and gas operations. Some of theseworkers may be organised into labour unions. Any strike activity or labour unrest in any such localjurisdiction or at any oil and gas operation could adversely affect the Group’s ongoing operations and itsability 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 couldmaterially adversely affect the Group’s reputation and the market price of the Ordinary Shares and/or theExchangeable SharesAs disclosed in Section 9 ‘‘History and Development’’ of Part I of this document, prior to 1998, the ChiefExecutive Officer of the Company had associations with certain companies, namely Executive Outcomesand 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, theChief Executive Officer has had no association with any private military contractors or similar companiesor activities and the Group has no assets or current intentions to operate in the countries in whichExecutive Outcomes and Sandline International operated. Further, there is no connection between theassets of the Company and the previous involvement of the Chief Executive Officer with private militarycontractors 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 periodicallybe in the future, media and other public speculation about the Chief Executive Officer’s associations withprivate military contractors and/or individuals involved with those types of companies. Any adverse mediaspeculation or other public statements about the Chief Executive Officer could materially adversely affectthe Group’s reputation and the market price of the Ordinary Shares.19

Risks Relating to the Countries in which the Group OperatesDeveloping Countries are Subject to Greater Risk than Developed CountriesCertain of the Group’s significant oil and gas interests are located in developing countries some of whichhave historically experienced periods of civil unrest, terrorism, violence and war, as well as political andeconomic instability. Future oil and gas exploration and development activities in such developingcountries may be affected in varying degrees by government regulations, policies or directives with respectto restrictions on production or sales, price controls, export controls, repatriation of income, changes inincome taxes and other local tax laws, carried interests for the state, expropriation of property andenvironmental legislation. There are inherent risks of uncertainty in, and changes to, laws such as tax lawsin such developing countries. The Group will also be required to negotiate property developmentagreements with the governments having jurisdiction over some of its properties. Such governments mayimpose conditions that could affect the viability of any given project such as providing the government withfree carried interests, requiring local company participation, or providing subsidies for the development ofthe local infrastructure or other social assistance. There can be no assurance that the Group will besuccessful in concluding such agreements with any relevant governmental entity on commerciallyacceptable terms or that these agreements will be successfully enforced in the foreign jurisdictions in whichthe Group’s properties are located. Operations may also be affected in varying degrees by political andeconomic instability such as frequent changes to tax laws or fiscal policy, economic or other sanctionsimposed 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 politicalstatus of certain countries in which the Group operates may make it more difficult, in particular aftertwelve months from the date of this document, for the Group to obtain any required project financing fromsenior lending institutions because such lending institutions may not be willing to finance projects in thesecountries due to the perception of investment risk.Infrastructure development in many of the countries in which the Group operates is limited. In addition, asignificant portion of the Group’s properties are located in remote areas, many of which are difficult toaccess, and some countries in which the Group operates such as Uganda, are landlocked and have poorinfrastructure. The Group has recently encountered supply and transport difficulties into and out ofUganda due to the political and civil unrest in neighbouring Kenya, and the main trade route to Mombasaon the Kenyan coast has intermittently been closed off since troubles in Kenya escalated, although thesituation has improved in March 2008. These factors may affect the Group’s ability to explore and developits properties and to store and transport its oil and gas production. There can be no assurance that futureinstability 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 amaterial 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 PersonnelCertain countries where the Group has interests have a publicised history of political and social instabilitywhich culminate in security problems and which may affect the Group, its operations and its personnel. Itmay 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 aresult, the Group’s insurance programme may exclude this coverage. Consequently, such risks could have amaterially 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, guerrillaactivities, military repression, civil disorder, crime, stability of the workforce, extreme fluctuations incurrency exchange rates and high inflation. Any changes in regulations or shifts in economic (including taxor fiscal policy) or political conditions are beyond the control of, and may adversely affect, the Group’sbusiness, financial condition, results of operations and prospects.RussiaDespite Russia’s broad shift to a market-oriented economy and democratic institutions, the Russianpolitical system remains vulnerable to the consequences of large-scale privatisations in the 1990s anddemands for autonomy from certain regional and ethnic groups. Since President Putin was elected inMarch 2000, Russia has generally experienced a significantly higher degree of governmental stability, withthe government establishing control over the private interest groups that flourished during the Yeltsin20

years. In addition, since December 2003 the lower houses of Russia’s parliament have been dominated bypolitical parties in support of former President Putin, which has translated into a period of stability andprosperity for Russia at large. Possible future changes in the government, major policy shifts or anypossible lack of consensus between the president, the government, Russia’s parliament and powerfuleconomic lobby groups could lead to political instability, which could have a material adverse effect on theGroup’s operations in Russia.In Russia, the division of authority between federal and regional authorities in respect of the developmentand implementation of state policy, in relation to the exploration, production, transport and sale of oil andgas and the industrial and environmental safety concerns may lead to a climate of uncertainty in theGroup’s Russian operations. Such uncertainty could hinder the Group’s long-term planning efforts inRussia, and may create uncertainties in its operating environment. These uncertainties may also preventthe Group from effectively and efficiently carrying out its business strategy in respect of its Russianoperations.KRIIn October 2007, the Group, through a wholly-owned subsidiary, entered into a PSC with the governmentof the KRI to explore for oil and gas in the KRI. The KRI is located in northern Iraq. Iraq is currentlyexperiencing periods of civil unrest and political and economic instability. In addition, the Government ofTurkey recently authorised Turkey’s military to make incursions into Iraq in order to carry out cross-borderassaults against the Kurdistan Workers Party. The Turkish military has recently amassed a significantnumber of troops along the Iraqi border, and has carried out air strikes and conducted limited shelling oftargets in northern Iraq.Additionally, the national government of Iraq has been considering and may bring into force a newpetroleum law, and the PSC with the KRI may, accordingly, be subject to challenge or changes once such afederal law comes into effect. As at the date of this document, the new Iraqi petroleum law has yet to bebrought into force and it is not clear how the Iraqi government and U.S. State Department sentiment willaffect the Group’s interests in the KRI. Furthermore, the Group received a letter from the Iraq Ministry ofOil dated 17 December 2007, stating that contracts signed with the KRG without the prior approval of thegovernment 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 Iraqigovernment authorities or others and the validity and effectiveness of and enforcement of such PSC in Iraqcannot be assured. This could have a materially adverse effect on the Group’s ability to obtain oil and gaslicences in other areas of Iraq.No assurances can be given that the Group will be able to maintain or obtain effective security or insuranceof any of its assets or personnel in Iraq where, at times, terrorism and insurgent activities have disruptedvarious 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 withinIraq to assist the new local government to maintain peace and national security and law and order at thenational level. There can be no assurances that the commitment of these foreign nations to maintain theirmilitary presence will continue in the short to medium term nor can there be assurances that the localgovernment of Iraq can itself provide the necessary degree of peace, order, stability and security withoutforeign military assistance. As such, the Group’s ability to maintain effective security over its assets may beadversely impacted in the KRI.UgandaThe Group holds rights to explore and develop oil and gas properties in and around Lake Albert, whichstraddles the border of Uganda and the DRC. There is a long history of war and other forms of hostilitybetween Uganda and the DRC, and both countries have experienced civil conflict, terrorism and guerrillaactivities 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 thesecountries will not continue.DRCThe DRC has a history of prolonged periods of war and pronounced political and civil unrest. Whilstconsiderable efforts have been made to bring stability to the country, there remains some unrest in theDRC, although this is mostly in the north-eastern region. As a result, the Group’s operations may beexposed 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, exportcontrols, income taxes, nationalisation or expropriation of property, repatriation of income, royalties andenvironmental legislation.The DRC PSC has not yet been ratified by the DRC government authorities and may, therefore, be subjectto further detailed negotiation. Furthermore, the work programme pursuant to the DRC PSC cannotcommence prior to the grant of a presidential decree from the DRC government. There can be noassurance that ratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscalterms will not be re-negotiated at a later date by the DRC government. The DRC licences are currentlybeing disputed by the Congolese Oil Ministry; this is being rigorously defended by the Group and itspartner. Accordingly, it is possible that if such PSC is not ratified in its current form, this could have amaterial adverse effect on the Group’s business, results of operations, financial condition and prospects.PakistanThe Group holds rights to explore and develop an oil and gas property in the province of Baluchistan ofPakistan. The province has experienced civil conflict, terrorism and guerrilla activities for a numberof decades.It May be Expensive and Logistically Burdensome to Discontinue Operations Should Economic, Physical orOther Conditions Subsequently DeteriorateOnce the Group has an interest in an established oil and gas exploration and/or production operation in aparticular country, it may be expensive and logistically burdensome to discontinue such operation shouldeconomic, physical or other conditions subsequently deteriorate. Such deterioration in any of the countriesin which the Group operates could be caused by some of the factors described below, and could have amaterial adverse effect on the Group’s ability to continue to exploit its established oil and gas explorationand/or production prospects in these countries.RussiaRussia experienced a significant economic crisis in the late 1990s which was instigated by the Russiangovernment’s default on its rouble-denominated fixed income securities and a temporary moratorium wasimposed on certain hard currency payments. These actions culminated in a severe devaluation of therouble and a sharp increase in the rate of inflation. Since this crisis, the Russian economy has experiencedpositive trends, such as an increase in gross domestic product, a relatively stable rouble, a reduced rate ofinflation and rising prices in world markets for the crude oil and gas that Russia exports. No assurance canbe given that such positive trends will continue and a decline in the prices of crude oil and gas could havean adverse effect on Russia’s economy.Certain of the Group’s capital costs relating to equipment hires and purchases and employee salaries inrespect of its operations in Russia may be materially affected by increased inflation rates in Russia which inturn could affect the Group’s operating profits, financial condition and results of operations.KRIAs a direct result of the actions of the Kurdistan Workers Party, de facto economic sanctions have beenimposed 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 thesouthern regions of the country. The stability of the KRI (compared to other regions of Iraq) has allowed itto achieve a higher level of development than other regions in Iraq. In 2004 the per capita income in theKRI was 25 per cent. higher than in the rest of Iraq.Following the removal of Saddam Hussein’s administration and the subsequent violence, the threeprovinces fully under the KRG’s control were the only three in Iraq to be ranked ‘‘secure’’ by theU.S. military. The relative security and stability of the region has allowed the KRG to sign a number ofinvestment contracts with foreign companies. No assurance can be given that such stability and positiveeconomic growth will continue and an overspill of violence and social and political instability from otherregions of Iraq and the Turkish border regions of the KRI could have an adverse effect on theKRI’s economy.22

UgandaUganda is among the poorest countries in the world with a predominantly agricultural economy and ahistory of civil strife and political instability although the country has made significant socio-politicalimprovements in the last two decades. Rural Uganda has an underdeveloped infrastructure andproductivity; competitiveness and capital development expenditure are also low.DRCThe DRC is an impoverished country with physical and institutional infrastructure that is often in adilapidated condition. It is in transition from a largely state controlled economy to one based on freemarket principles and from a non-democratic political system with a centralised ethnic power base to apolitical 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 marketprice at which it sells the oil and gas it produces (except to the extent that it enters into forward sales andother derivative contracts), it is possible that high inflation rates in the DRC in the future could result in anincrease in future operational costs in Congolese Francs and have a material adverse effect upon theGroup’s business, results of operations and financial condition.PakistanPakistan has suffered from decades of internal political disputes (including the recent assassination ofBenazir Bhutto), low levels of foreign investment, and a costly, ongoing confrontation with neighbouringIndia. Despite employing International Monetary Fund-approved policies, bolstered by generous foreignassistance, renewed access to global markets and overall decreases in poverty levels by 10 per cent. since2001, inflation remains the biggest threat to the economy, jumping to more than 9 per cent. in 2005 beforeeasing to 7.9 per cent. in 2006. It is possible that high inflation rates in Pakistan in the future could result inan increase in future operational costs in Pakistani Rupees and have a material adverse effect upon theGroup’s business, results of operations and financial condition.Uncertainties of Legal Systems in Jurisdictions in Which the Group OperatesRussia, Uganda, the DRC, the KRI and other jurisdictions in which the Group operates or might operatein the future may have less developed legal systems than more established economies which could result inrisks such as (i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach oflaw or regulation, or in an ownership dispute, being more difficult to obtain; (ii) a higher degree ofdiscretion and corruption on the part of governmental authorities; (iii) the lack of judicial or administrativeguidance on interpreting applicable local rules and regulations; (iv) inconsistencies or conflicts betweenand within various laws, regulations, decrees, orders, resolutions and judgements; or (v) relativeinexperience of the judiciary and courts in such matters. In certain jurisdictions, the commitment of localbusiness people, government officials and agencies and the judicial system to abide by legal requirementsand negotiated agreements may be more uncertain, creating particular concerns with respect to theGroup’s licences and business agreements. Some or all of these may be susceptible to revision orcancellation and legal redress may be uncertain, unavailable or delayed. Equally, there can be no assurancethat PSCs, concession agreements, joint ventures, licences, licence applications or other legal arrangementswill not be adversely affected by the actions of government authorities or others and the effectiveness ofand enforcement of such arrangements in these jurisdictions cannot be assured.Failure to Meet Contractual Agreements May Result in the Loss of the Group’s InterestsAny change in government or legislation may affect the status of the Group’s PSCs or contractualarrangements or its ability to meet its contractual obligations and may result in the loss of its interests in itsoil and gas properties. Some of the contracts pursuant to which the Group holds an interest in itsproperties permit the other party to terminate the contract if force majeure conditions cause operations tobe economically unviable or interrupted for more than thirty days. Due to the potential for civil unrest incertain countries in which the Group’s properties are located, there can be no assurance that theseproperties will not become subject to force majeure conditions for more than thirty days which could havethe consequence of putting those contractual interests at risk. The laws of Jersey do not apply to any ofthese contractual arrangements and no assurance can be given that these contractual arrangements will beenforced or interpreted in the same manner or to the same extent as would be the case if the laws of Jerseydid apply.23

Failure to Follow Corporate and Regulatory Formalities May Call Into Question the Validity of the Entity orits AssetsIn Russia and other jurisdictions in which the Group may obtain interests, both the conduct of itsoperations and the steps involved in the Group acquiring its current interests involve or may involve theneed to comply with numerous procedures and formalities including in relation to obtaining explorationand production licences. In some cases, failure to follow such formalities or obtain relevant evidence ofcompliance with such formalities may call into question the validity of the entity or the actions taken. Inparticular, there are various requirements under the Group’s PSCs which, if not complied with could leadto the PSCs being terminated or make them difficult to enforce or rely upon in the local courts to assertthe Group’s rights and interests, including the minimum expenditure required during the explorationperiod.Risks Relating to the Group StructureConcentration of Investments in HOCThe Company will be the ultimate controlling shareholder of HOC. Assuming full completion of the HOCSubscription, DutchCo will own, 100 per cent. of the HOC Common Shares. The purpose of the Companyis 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 significantadverse effect on the returns received by the Company from HOC and on the price of the Ordinary Shares.Lack of Operating HistoryThe Company is a newly formed company incorporated under the laws of Jersey on 6 February 2008 and assuch has only a limited operating history. The Company was incorporated on the instigation of HOC forthe purposes of a corporate reorganisation through the Plan of Arrangement. Under the Plan ofArrangement the shareholders of the HOC Common Shares have been offered the Ordinary Shares andthe Exchangeable Shares in return for their HOC Common Shares. As the Company is newly formed itdoes not directly hold any assets other than the right of membership in DutchCo, Jersey SubCo andAlberta 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 ofCompanies Incorporated in Other JurisdictionsThe Company is incorporated in Jersey under the Act. As a result, the rights of Shareholders will begoverned by the laws of Jersey and the Articles. The rights of Shareholders under the laws of Jersey maydiffer from the rights of shareholders of companies incorporated in other jurisdictions and theenforcement of such rights may involve different considerations and may be more difficult than would bethe 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 CourtsWhile the Company exists under the laws of Jersey and its registered office is located in Jersey, a numberof Directors of the Group (other than Mr. Anthony Buckingham and Mr. Paul Atherton who intend toreside in Jersey in the near future) and substantially all of the assets of the Group are located outsideJersey. It may not be possible for holders of Ordinary Shares to effect service of process within Jersey uponthe Directors who reside outside Jersey. As such, there may be difficulty in enforcing against the Group’sassets, and judgments obtained in Jersey courts based upon the provisions of applicable Jersey securitieslegislation may not be recognised or enforceable in jurisdictions where certain of the Directors reside orwhere the Group’s assets are located.Risks Relating to the Ordinary Shares and the Exchangeable SharesNo Prior Market for the Ordinary Shares and the Exchangeable SharesPrior to the Plan of Arrangement, there will have been no public trading market for the Ordinary Shares orthe Exchangeable Shares. Although HOC Common Shares are currently listed and traded on the TorontoStock Exchange, the Directors can give no assurance that an active trading market for the Ordinary Sharesor the Exchangeable Shares will develop or, if it develops, will be sustained following Admission. If anactive trading market does not develop or is not maintained, the liquidity and trading price of the OrdinaryShares or the Exchangeable Shares could be adversely affected and investors may have difficulty sellingtheir Ordinary Shares or their Exchangeable Shares.24

Market Price of the Ordinary Shares and the Exchangeable Shares May Fluctuate SignificantlyThe market price of the Ordinary Shares and the Exchangeable Shares may, in addition to being affectedby the Group’s actual or forecasted operating results, fluctuate significantly as a result of factors beyondthe 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 ofthe 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 inwhich 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 certaincircumstances, including a failure to meet continuing listing obligations of the LSE.Trading Price of the Exchangeable SharesHolders of the Exchangeable Shares, as nearly as practicable, will have the rights that are economicallyequivalent to the rights of the holders of Ordinary Shares. An application will be made for the admission ofthe Ordinary Shares and the Exchangeable Shares to listing on the Official List. Since they will be separatelistings, the trading prices of the Ordinary Shares and the Exchangeable Shares may not reflect equivalentvalues. This may result in the holders of Exchangeable Shares having to exchange their ExchangeableShares 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 ofthe CompanyAs at Admission, the Major Shareholder and Mr. Anthony Buckingham will own and control in aggregate84,540,340 Ordinary Shares representing approximately 33.2 per cent. of the aggregate voting shares of theCompany. As a result of its ownership interest, the Major Shareholder, and thereby Mr. AnthonyBuckingham, has the ability to exert significant influence on some of the actions taken by the shareholdersof the Company. The Major Shareholder, and thereby Mr. Anthony Buckingham, currently has sufficientvoting power to, among other things, delay, deter or prevent a change in control of the Company thatmight otherwise be beneficial to its shareholders and may also discourage acquisition bids for the Companyand limit the amount certain investors may be willing to pay for the Ordinary Shares or the ExchangeableShares. Each of the Major Shareholder and Mr. Anthony Buckingham have entered into a relationshipagreement with the Company dated 28 March 2008 to ensure that the Group is capable of carrying onbusiness independently from the Major Shareholder and that transactions and relationships with the MajorShareholder are at arm’s length and on normal commercial terms.There Are Potential Conflicts of Interest to Which the Directors, the Senior Manager and PrincipalShareholders of the Company Will be Subject to in Connection With the Operations of the GroupThere are potential conflicts of interest to which the Directors, the Senior Manager and principalshareholders of the Company will be subject to in connection with the operations of the Group. Some ofthe Directors, the Senior Manager and principal shareholders are or may become engaged in other oil andgas interests on their own behalf and on behalf of other companies, and situations may arise where thedirectors and officers will be in direct competition with the Company. Conflicts, if any, will be subject tothe procedures and remedies under the Act. The Directors and the Senior Manager of the Company maynot devote their time on a full-time basis to the affairs of the Company. Certain Directors and the SeniorManager of the Group own collectively, directly and indirectly, a significant part of the issued share capitalof 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 Sharesand the Exchangeable SharesAs of the date of this document, HOC has proposed the Plan of Arrangement to its shareholders that givesshareholders the ability to exchange their HOC Common Shares for Ordinary Shares or, in certain25

circumstances, for Exchangeable Shares. The shareholders of HOC who elect to exchange their HOCCommon Shares for Ordinary Shares or Exchangeable Shares are not subject to any contractualrestrictions imposed by HOC or the Company regarding selling their Ordinary Shares or ExchangeableShares. The Company cannot predict whether substantial numbers of the Ordinary Shares orExchangeable Shares received by HOC shareholders will be sold in the open market. Sales of a largenumber of the Ordinary Shares or Exchangeable Shares in the public markets, or the potential for suchsales, could decrease the market price of the Ordinary Shares and the Exchangeable Shares and couldimpair 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 aggregate84,540,340 Ordinary Shares representing approximately 33.2 per cent. of the aggregate voting shares of theCompany. The Company cannot predict whether the Major Shareholder or Mr. Anthony Buckingham willsell any of the Ordinary Shares they hold in the open market. Sales by the Major Shareholder orMr. Anthony Buckingham of a large number of the Ordinary Shares in the public markets, or the potentialfor such sales, could decrease the trading price of the Ordinary Shares and the Exchangeable Shares, andcould 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 AssetsThe 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 theassets of HOC or to cause the liquidation or bankruptcy of that company under applicable bankruptcylaws. Creditors of HOC would be entitled to payment in full from such assets before the Company, as ashareholder, would be entitled to receive any distribution therefrom. Claims of creditors of HOC will havepriority with respect to the assets and earnings of HOC over the claims of the Company, except to theextent that the Company may itself (via its indirectly wholly-owned subsidiary DutchCo) be a creditor withrecognised claims against HOC ranking at least pari passu with such other creditors, in which case theclaims of the Company would still be effectively subordinate to any mortgage or other liens on the assets ofHOC and would be subordinate to any indebtedness of HOC.Raising of Future Equity Funds for the Company Could Result in DilutionDepending on future exploration, development, production or acquisition plans, the Group may, aftertwelve months from the date of this document, require additional financing and the Company may chooseto raise such additional finance by way of an equity offering of additional Ordinary Shares. Any suchoffering may be dilutive to the existing shareholders’ interests in the Company. In addition, if anyoutstanding options or convertible bonds are exercised subsequent to Admission, further dilution of theexisting shareholders’ interests in the Company will occur.Payment of Dividends is Subject to the Company Having Sufficient Distributable ReservesThe payment of dividends by the Company is subject to the Company having sufficient distributablereserves 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 EquityRights OfferingU.S. and Canadian shareholders may not be entitled to exercise pre-emption rights unless the rights andthe Ordinary Shares are registered under applicable U.S. or Canadian securities legislation or anexemption from the registration requirements of such legislation is available. The Directors cannot at thistime predict whether the Company would seek such registration and the Company would evaluate, at thetime of any rights offering, the costs and potential liabilities associated with registration or qualifying for anexemption, as well as the indirect benefits to the Company of enabling U.S. and Canadian shareholders toexercise rights and any other factors the Company considers appropriate at that time, prior to making adecision whether to file a registration statement or prospectus or utilise an exemption from the registrationrequirements of applicable U.S. and Canadian securities legislation.Jersey Law Significantly Limits the Circumstances Under Which Shareholders of Companies May BringDerivative ActionsThe rights afforded to Shareholders will be governed by Jersey law and by the Company’s constitutionaldocuments and these rights differ in certain respects from the rights of shareholders in typical U.S. andCanadian corporations. In particular, Jersey law limits the circumstances under which shareholders ofcompanies may bring derivative actions, and, in most cases, only the company can bring an action inrespect of any wrongful act committed against it. Under Jersey law derivative actions are available toshareholders 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 toshareholders 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 ADVISERSDirectors Michael Hibberd (Chairman and Non-ExecutiveDirector)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 SecretaryWoodbourne Secretaries(Jersey) LimitedOrdnance House31 Pier RoadSt HelierJersey JE4 8PWChannel IslandsSenior Manager Brian Smith (VP Exploration)Registered Office of theOrdnance HouseCompany31 Pier RoadSt HelierJersey JE4 8PWChannel IslandsHead Office and Directors’ 28-30 The ParadeBusiness AddressSt HelierJersey JE1 1BGChannel IslandsU.K. Office of the Company 34 Park StreetLondon W1K 2JDUnited KingdomSponsorJPMorgan Cazenove Limited20 MoorgateLondon EC2R 6DAUnited KingdomEnglish Legal Advisers to the McCarthy TétraultCompanyRegistered Foreign Lawyers &Solicitors2nd Floor5 Old BaileyLondon EC4M 7BAUnited KingdomCanadian Legal Advisers to the McCarthy Tétrault LLPCompany Suite 3300421 7th Avenue S.W.CalgaryAlberta T2P 4K9Canada27

Jersey Legal Advisers to theCompanyEnglish Legal Advisers to theSponsorCanadian Legal Advisers to theSponsorAuditors and ReportingAccountants of the CompanyAuditors of HOCRegistrars of the CompanyPrincipal Bankers of theCompanyIndependent PetroleumEngineering Consultants to theCompanyVoting Trustee for the SpecialVoting Share in the CompanyMourant du Feu & Jeune22 Grenville StreetSt HelierJersey JE4 8PXChannel IslandsLinklaters LLPOne Silk StreetLondon EC2Y 8HQUnited KingdomStikeman Elliott LLPDauntsey House4B Frederick’s PlaceLondon EC2R 8ABUnited KingdomKPMG LLP U.K.8 Salisbury SquareLondon, EC4Y 8BBUnited KingdomKPMG LLP CanadaNationalLocalSuite 3300205-5 th Avenue S.W.Commerce Court WestBow Valley Square II199 Bay Street Calgary, AlbertaToronto, OntarioT2P 4K9M5L 1B2CanadaCanadaComputershare Investor Services(Channel Islands) LimitedOrdnance House31 Pier RoadSt HelierJersey JE4 8PWChannel IslandsRoyal Bank of Canada (Canada)Standard Bank (Europe)Bank of Scotland (Europe)RPS EnergyGoldsworth HouseDenton WayGoldsworth ParkWokingSurreyGU21 3LGUnited KingdomComputershare Trust Companyof CanadaSuite 600530 8 th Avenue S.W.CalgaryAlberta T2P 3S8Canada28

EXPECTED TIMETABLE OF PRINCIPAL EVENTSPlan of Arrangement becomes effective and the Company becomes theultimate holding company of the Group (1) .................... 31 March 2008Admission and expected commencement of dealings in the OrdinaryShares on the London Stock Exchange ...................... 8.00 am on 31 March 2008Ordinary Shares credited to CREST accounts ................... 31 March 2008Last day of dealing in the HOC Common Shares ................ 2April 2008De-listing of HOC Common Shares from TSX .................. 2April 2008Admission and expected commencement of dealings in theExchangeable Shares on the London Stock Exchange ............ 8.00 am on 2 April 2008Listing of Exchangeable Shares on TSX ....................... 2 April 2008Despatch of definitive share certificates (where applicable) .........The week commencing 7 April2008Notes:(1) These dates are indicative only and will depend, among other things, on the date upon which the Court sanctions the Planof Arrangement.All times are London times unless specifically stated otherwise. Each of the times and dates in the abovetimetable are subject to change without further notice.29

FORWARD-LOOKING STATEMENTS AND OTHER INFORMATIONThis document includes statements that are, or may be deemed to be ‘‘forward-looking statements’’. Thewords ‘‘believe’’, ‘‘anticipate’’, ‘‘expect’’, ‘‘intend’’, ‘‘aim’’, ‘‘plan’’, ‘‘predict’’, ‘‘continue’’, ‘‘assume’’,‘‘positioned’’, ‘‘may’’, ‘‘will’’, ‘‘should’’, ‘‘shall’’, ‘‘risk’’ and other similar expressions that are predictions ofor indicate future events and future trends identify forward-looking statements. These forward-lookingstatements 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’sstrategy, plans, objectives, goals and other future events or prospects are forward-looking statements. Aninvestor should not place undue reliance on forward-looking statements because they involve known andunknown risks, uncertainties and other factors that are in many cases beyond the Group’s control. By theirnature, forward-looking statements involve risks and uncertainties because they relate to events anddepend on circumstances that may or may not occur in the future. The Company cautions investors thatforward-looking statements are not guarantees of future performance and that its actual results ofoperations, prospects, financial condition and liquidity, and the development of the industry in which itoperates, may differ materially from those made in or suggested by the forward-looking statementscontained in this document. The cautionary statements set forth above should be considered in connectionwith any subsequent written or oral forward-looking statements that the Group, or persons acting on itsbehalf, may issue. Factors that may cause the Group’s actual results to differ materially from thoseexpressed or implied by the forward-looking statements in this document include but are not limited to therisks described under ‘‘Risk Factors’’.Presentation of Financial and Statistical InformationPresentation of Financial InformationFinancial information in relation to the Group means, for the purposes of this paragraph, the informationin 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 forthe three years ended 31 December 2004, 31 December 2005 and 31 December 2006 and the nine-monthperiod ended 30 September 2007 and from the unaudited consolidated financial statements of HOC forthe nine-month period ended 30 September 2006 as set out in Part VII of this document and is to be foundin the ‘‘Selected Financial Information’’ section and Part IV of this document. Investors should ensure thatthey read the whole of this document and not just rely on key information or information summarisedwithin it.The consolidated financial statements in Part VII(B) of this document for the two years ended31 December 2005 and 31 December 2006 and the nine-month period ended 30 September 2007 and forthe nine-month period ended 30 September 2006 were prepared in accordance with IFRS and theconsolidated financial statements in Part VII(C) of this document for the years ended 31 December 2004and 31 December 2005 have been prepared in accordance with Canadian GAAP. A statement ofreconciliation highlighting the differences in the financial statements prepared in accordance withCanadian GAAP and the financial statements prepared in accordance with IFRS, both for the year ended31 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 twoyears ended 31 December 2005 and 31 December 2006 and the nine-month period ended30 September 2007 have been applied consistently in Part VII of this document. The significant CanadianGAAP accounting policies applied to the financial information of the Group, as applicable, for thefinancial years ended 31 December 2004 and 31 December 2005 have been applied consistently in thefinancial information in Part VII of this document.IFRS differs in certain material respects from Canadian GAAP. Except as stated above, the Group has notprepared 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 ownexamination of the Group and the financial information in this document. Prospective investors shouldconsult their own professional advisers for an understanding of the differences between Canadian GAAPand IFRS.30

CurrenciesAll references in this document to ‘‘Pounds Sterling’’, ‘‘Pounds’’, ‘‘£’’, ‘‘p’’ or ‘‘pence’’ are to the lawfulcurrency 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. Allreferences in this document to ‘‘Cdn$’’, ‘‘C$’’ or ‘‘Canadian cents’’ are to the lawful currency of Canada.PercentagesPercentages 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 ofdata presented in this document may vary slightly from the actual arithmetic totals of such data.Operating InformationAny unaudited operating information in relation to the Group’s business is derived from the followingsources: (i) management accounts for the relevant accounting period presented directly from the Group’saccounting system (based on invoices issued and/or received); (ii) internal financial reporting systemssupporting the preparation of financial statements; (iii) management assumptions and analyses and(iv) discussions with key operating personnel. Operating information derived from management accountsor internal reporting systems in relation to the Group’s business is to be found principally in Part V ofthis document.Production FiguresAll references in this document to ‘‘production’’ are to such stated production figures that are net to theGroup unless specified otherwise.Presentation of Reserves and ResourcesAll references to ‘‘reserves’’ and ‘‘resources’’ are to proved and probable in the case of reserves andcontingent and prospective in the case of resources.Forecasts of reserves and associated net production revenues are forward-looking statements based onjudgments 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 geologicalinterpretation and judgment. This document should be accepted with the understanding that reserves andfinancial performance subsequent to the date of the estimates may necessitate revision. These revisionsmay be material.All reserves are quoted as the Group’s net entitlement interest, which is net of any applicable Stateroyalties. In the case of properties within PSC areas, the Group’s net entitlement to cost oil and profit oilaccording to the terms of the PSC assuming forecast price and cost assumptions as evaluated in reportsprepared by RPS. For information purposes, reserves are also presented as the Group’s working interestshare 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 theGroup’s properties. All estimates of present value are stated prior to provision for indirect costs andcalculated 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 thePRMS has been reproduced in its entirety in Part III of this document and is defined, for the purposes ofthis document, as the ‘‘Technical Report’’. The Technical Report was commissioned by the Company andwas prepared specifically for the purposes of this document but it has not been amended or updated for thepurposes of its inclusion in this document.The Technical Report is a statement of the estimated oil and gas reserves attributed to the Company as at30 September 2007. This estimate is based on technical information supplied by the Company to RPS. Thetechnical information supplied by the Company to RPS was not independently verified by RPS and is theresponsibility of the management of the Company. In accordance with usual standard industry practice, alltechnical information that was obtained from the Company or from public sources was accepted, without31

further investigation. It is RPS’s opinion that the technical information received from the Company wasreasonable, based on similar evaluations prepared by RPS.RPS used the technical information to produce the reserves and resource estimates which formed the basisof the Technical Report. The reserves estimates comprise the proved, probable and possible reserves andrelated estimated future net revenues which are based on the technical information, and continues to be theresponsibility of the Board. The reserves and resources were estimated by RPS in accordance withstandards set out in the PRMS.Having carried out the evaluation on the basis set out above, RPS has provided an independent reserves andresource estimates which have been determined and presented in accordance with the PRMS.GeneralIMPORTANT INFORMATIONEach of the Ordinary Shares and the Exchangeable Shares have not been, and will not be, registered underthe securities laws of either Japan or Australia, or any other jurisdiction although the Company will be areporting issuer in the Provinces of Alberta, British Columbia and Ontario in Canada and regulatoryclearance 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 tosell, or the solicitation of an offer to subscribe for or buy, any Ordinary Shares or the Exchangeable Sharesto any person in any jurisdiction to whom or in which such offer or solicitation is unlawful and is not fordistribution 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 publicoffering of the Ordinary Shares or the Exchangeable Shares, or possession or distribution of this documentor 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 orindirectly, and neither this document nor any other offering material or advertisement in connection withthe Ordinary Shares or the Exchangeable Shares may be distributed or published in or from any country orjurisdiction except under circumstances that will result in compliance with any applicable rules andregulations of any such country or jurisdiction.Any failure to comply with these restrictions may constitute a violation of the securities laws of any suchjurisdiction. This document does not constitute an offer to subscribe for or buy any of the Ordinary Sharesor the Exchangeable Shares described herein to any person in any jurisdiction to whom it is unlawful tomake such offer or solicitation in such jurisdiction.United StatesThe Ordinary Shares and the Exchangeable Shares have not been and will not be registered under theUnited States Securities Act of 1933, as amended (the ‘‘US Securities Act’’) and may not be offered or soldwithin the United States except pursuant to an applicable exemption from, or in a transaction not subjectto the registration requirements of the US Securities Act, and in compliance with any applicable securitieslaws 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 theExchangeable Shares an offer or sale of the Ordinary Shares or the Exchangeable Shares within the UnitedStates by any dealer (whether or not participating in the offering) may violate the registrationrequirements of the US Securities Act.WebsitesThe Company’s and HOC’s websites are www.heritageoilcorp.com or www.heritageoilltd.com. Theinformation on these websites or any website mentioned in this document or any website directly orindirectly linked to these websites has not been verified and is not incorporated by reference into thisdocument and investors should not rely on it.32

PART I—INFORMATION ON THE GROUPOVERVIEW1. INTRODUCTIONThe Company was incorporated in Jersey on 6 February 2008 to be the ultimate holding company of theGroup. The Group was established in 1992 (with HOC being incorporated on 30 October 1996) as anindependent upstream exploration and production group engaged in the exploration for, and thedevelopment, production and acquisition of, oil and gas in its core areas of Africa, the Middle East andRussia. HOC, being a member of the Group and in anticipation of the Admission, has proposed areorganisation of its share capital. The reorganisation will culminate in the creation of the ExchangeableShares which will be subject to voting rights and terms and conditions different from the Ordinary Sharesbut which, subject to certain conditions, will be exchanged for Ordinary Shares on a one-to-one basis. HOCintends to (at or immediately following Admission) procure the admission of the Exchangeable Shares totrading on both the TSX and on the Official List together with admission to trading on the London StockExchange’s main market for listed securities. See ‘‘Corporate Reorganisation’’ Part IX of this document forfurther information on the reorganisation of HOC’s share capital and the voting and other rights attachingto the Exchangeable Shares and see ‘‘Additional Information’’ in section 6.3 of Part X for furtherinformation 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, andproducing properties in Oman and Russia. The Group’s management team believes that it hasdemonstrated a track-record of finding new substantial discoveries, particularly in Africa, including thehydrocarbon system in the Albert Basin, Uganda and the M’Boundi oilfield in Congo. The Group’sproducing, development and exploration projects, together with potential opportunities, provide acombination 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’’ insection 11 of Part I of this document for further information on the origins of the Group and itsdevelopment.All references in this Part I of the document to ‘‘production’’ are to such stated production figures that arenet to the Group unless specified otherwise.2. SUMMARY OF GROUP ASSETSThe Group has a portfolio of production, development and exploration assets focussed on Africa, theMiddle East, Russia and the Mediterranean. Management has focussed the Group’s efforts on large areaswith 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 bblsproved and probable reserves net to the Group and average production of 342 bopd in February 2008. TheGroup 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 of0.15 million bbls (based on the Group’s entitlement interest) and net production is 109 bopd as atJanuary 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 firstphase of the West Bukha development has commenced and comprises design, fabrication and installationof the wellhead platform and pipeline with a tie into the Bukha facilities. Management believes thatproduction, subject to unforeseen circumstances, is likely to commence in the third quarter of 2008 and anagreement is in place to sell the gas from the West Bukha field to Rakgas for five years. The Group’sreserves 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 interestin Block 3A and as operator with a 50 per cent. interest in Block 1. The assets are currently in the appraisaland 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 workinginterest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at30 September 2007. The Government of Uganda has a back-in right which could, if exercised, reduce theGroup’s working interest to 42.5 per cent. In the event that these resources were to mature into reserves33

these barrels would be subject to the PSC arrangements in Blocks 3A and 1 and result in net entitlementreserves that reflect those arrangements.In October 2007, the Group executed a PSC with the KRI government over the Miran Block, which coversan area of 1,105 square km and is located only 55 km from the Kirkuk oilfield. The Group also enteredinto a separate strategic agreement with the KRG to establish a 50/50 joint venture company which shallbuild, 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 andmanagement 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 RESOURCESRPS has certified that as of 30 September 2007, the Group’s net working interest and entitlement reservesand value, using money of the day prices, discounted at 10 per cent., were as follows:Net Working Net NetInterest Entitlement PresentReserves Reserves ValueMMboe MMboe $MillionsProved ............................................. 25.5 24.2 30.3Probable Additional ................................... 40.3 37.9 229.3Total Proved + Probable ................................ 65.8 62.1 259.6Total Proved + Probable + Possible ....................... 171.5 163.9 824.1RPS has certified that the Group had a 50 per cent. working interest share of the mean risked workinginterest prospective resources from Blocks 3A and 1 in Uganda of 462 MMboe (923 MMboe gross) as at30 September 2007. The Government of Uganda has a back-in right which could, if exercised, reduce theGroup’s working interest to 42.5 per cent. In the event that these resources were to mature into reservesthese barrels would be subject to the PSC arrangements in Blocks 3A and 1 and result in net entitlementreserves that reflect those arrangements.4. GROUP STRENGTHS AND COMPETITIVE ADVANTAGESThe Directors believe that the Group has a number of key strengths and competitive advantages that areimportant 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 playsThe Group has a track-record of delivering growth in shareholder value through its strategy of focusing onhigh-impact international plays containing multiple targets with the potential to discover large reserves ofoil. The Group’s current focus areas are the Lake Albert region in Uganda and the DRC, the KRI andWest 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 appreciationand management of technical and political risk. This approach, together with the experience of theGroup’s management and technical teams, has enabled the Group to identify and be amongst the firstinternational oil companies to hold interests in territories such as Uganda, the eastern DRC and in recenttimes, the KRI.The Group has a proven track-record in sourcing deals, and has demonstrated its first-mover advantage inacquiring many of its assets resulting from the hands-on approach, flexibility and speed of the Group’smanagement team. The Group’s management team has demonstrated its ability to make substantial oildiscoveries and its flat and lean structure has enabled the Group to enjoy first-mover advantage in many ofits deals and to take advantage of interesting opportunities, such as the KRI and the Albert Basinin Uganda.34

Strong management and technical teamsThe 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 institutionalrelationships. These relationships enable the Group to form strategic alliances which reduce resourcecommitments and lower exploration and development risk, as well as give the Company accessto properties.Diversified portfolio of assetsThe 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, theMiddle East and Russia. In addition, the Group may from time to time invest in additional opportunisticplays, outside of these core geographies, if management believe that individual plays will enhanceshareholder value. Examples of investments in such opportunities include the Group’s recently acquiredinterests 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 hasproducing assets in Oman and the Zapadno Chumpasskoye licence in Western Siberia, a developmentproperty in Oman, together with exploration and appraisal properties in Uganda, the KRI, the DRC,Malta, Mali and Pakistan.Presence in the Albert Basin in UgandaThe Albert Basin in Uganda is considered by management to have the potential to contain significantquantities of oil. Assets in the Albert Basin in Uganda are controlled by the Group and Tullow, with theGroup partnered with Tullow on Blocks 3A and 1. Eight successful exploration and appraisal wells havebeen drilled in the basin since the beginning of 2006 with each of these wells having encountered oilbearingreservoirs. Of these, two wells tested at over 12,000 bopd. Further information is provided insection 6 of this Part I.First production is targeted by management to commence in the medium term, with potential productionestimated 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 inBlocks 1 and 2 on Lake Albert in the DRC to the adjacent Blocks 3A and 1 on the Ugandan side of theDRC/Uganda border. The potential exists for both assets to benefit from the proposed construction of aninternational export pipeline from Lake Albert to Mombasa on the east coast of Kenya.First-mover advantage in KurdistanThe Group was one of the first international oil companies to be awarded a PSC in the KRI. The Groupexecuted a PSC with the KRG over the Miran Block in the KRI on 2 October 2007. The Group has beenappointed operator.The Group has also entered into a separate strategic agreement with the KRG to establish a 50/50 jointventure company which shall build, own and operate an oil refinery in the vicinity of the Miran Block. Therefinery, which should have a capacity of 20,000 bopd, is scheduled to be operational to designspecification within approximately two years of the signing of the agreement.Historic track-record of creating value and generating cash to finance new developmentsHistorically, the Group has sold certain assets, notably in the Republic of Congo to create value forshareholders and generate cash which has been used to finance the development of other oil and gas assetsin the core areas. Further detail is provided in ‘‘History and Development’’ in section 9 of this Part I.Strong financial positionThe Directors believe that the Group has a strong financial position as a result of the proceeds from thecompletion of the private placement of $165.0 million of convertible bonds in February 2007 and theprimary 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 anddevelopment activities, potential strategic acquisitions, as well as for general working capital purposes.35

5. STRATEGYStrategyThe Group aims to continue to generate further growth in shareholder value by focusing on high-impactinternational plays containing multiple targets with the potential to discover substantial reserves of oil. TheGroup’s growth strategy is to acquire and invest in and then to explore and develop oil and gas propertiesthroughout 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 andinstitutional relationships, enabling it to gain access to a wide variety of new oil and gas businessopportunities and can provide the Group the competitive capability necessary to generate continuedgrowth for the Group.The Group believes that major oil companies, in the course of exploring large tracts of internationalacreage, frequently choose to ignore or abandon smaller discoveries, or discoveries with specialinfrastructure requirements. Comparatively smaller organisations, such as the Group, without theoverhead structures of larger organisations can often, through careful due diligence, planning and localintelligence, 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. TheGroup’s exploration strategy is to continue to focus on minimising financial exposure of the Companythrough effective portfolio management including industry farm-outs and the acquisition of workinginterests.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 closeassociation 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 andfacility optimisation, completions and development drilling. Once established in an area, the Grouppursues additional development and exploratory drilling in the surrounding area.Environmental, corporate and social responsibilityRespect for the environment and active engagement with local communities are fundamental to thebusiness of the Group. The Group’s objective is to minimise its impact on the environment and toundertake a series of community, conservation and education projects in certain countries in which itoperates. Historic or ongoing projects include building a school in the Lake Albert region, road buildingand rehabilitation of roads to improve access to local markets, drilling of community water wells, provisionof medical supplies and health checks, sponsorship of the ‘‘Save the Rhino Fund’’ and sponsorship of localindividuals’ attendance at universities.Acquisition StrategyWhen reviewing potential property acquisitions, the Group considers, amongst other things, the followingcriteria: the ability of the Group to enhance the value of a property through additional development andexploratory drilling, completion and tie-in of capped wells, additional exploitation efforts, includingimproved production practices, and improved marketing arrangements; the quality of production and reserves, in terms of product type, production rates, stability ofproduction, 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 capitalpayout of less than five years; the high-impact nature of an exploration programme and whether it has the possibility of findingsignificant quantities of hydrocarbons; the compatibility of a property with management’s organisational skills, capabilities and the Group’sexisting portfolio;36

the availability of existing infrastructure and the ability to expand that infrastructure in order toincrease 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 tobecome 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 notconform to all of these guidelines based upon the board’s consideration of the qualitative aspects of thesubject properties including their risk profile, technical upside, reserve life and asset quality.6. THE BUSINESSIntroductionThe 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 theMediterranean. Currently the principal areas of focus are Uganda, the KRI and West Siberia.The table below summarises the Group’s production properties.Proved plusGroupprobableProperty Block Working Designated reservesCountry Name number Interest Operator (MMboe)Oman .............. Bukha Block 8 10% RAK Petroleum 0.15Russia .............. Zapadno Zapadno 95% The Group 60.5Chumpasskoye ChumpasskoyeThe table below summarises the Group’s development properties.Proved plusGroupprobableProperty Block Working Designated reservesCountry Name number Interest Operator (MMboe)Oman ............... West Bukha Block 8 10% Rak Petroleum 1.5The table below summarises the Group’s exploration property.GroupBlock Working DesignatedCountry number Interest OperatorUganda ........................... Block 3A 50% The GroupUganda ........................... Block 1 50% The GroupKRI ............................. Miran 100% The GroupDRC............................. Block 1 39.5% TullowDRC............................. Block 2 39.5% TullowMali ............................. Block 7 75% (1) The GroupMali ............................. Block 11 75% (2) The GroupMalta ............................ Area 2 100% The GroupMalta ............................ Area 7 100% The GroupPakistan .......................... 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 nexttwo years.(2) This working interest can be earned by the Group by financing 100 per cent. of the minimum work programme over the nexttwo years.Overview of the Group’s PropertiesThe following is a description of the oil and gas properties, plants, facilities and installations in which theGroup has an interest and that are material to the Group’s operations and exploration activities,categorised by geographic region.37

RussiaRussia has the largest gas reserves and the eighth largest oil reserves in the world, estimated at60 billion bbls and 1,700 trillion cubic feet of gas (according to estimated figures stated in the CIA WorldFactbook as at 1 January 2006). The Western Siberian region, where the Zapadno Chumpasskoye field islocated, accounts for more than 60 per cent. of Russia’s oil production. There is increasing internationalinvestment in the Russian oil and gas industry.Map of Zapadno Chumpasskoye Licence and Surrounding AreaW E S T E R NS I B E R IAZAPADNOCHUMPASSKOYELICENCE4226230 10kmLEGENDHeritage PSAFieldsOil PipelinesGas PipelinesExploration & Appraisal Well14MAR20080054124538

In 2005, the Group acquired a 95 per cent. equity interest in ChumpassNefteDobycha, a Russian companywhose 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 fromNizhnevartovsk in the vicinity of TNK-BP’s prolific Samotlor field. The licence, which expires on7 September 2024, has an area of approximately 200 square km and contains a field which was discoveredin 1997. Zapadno Chumpasskoye has net 60.5 million bbls proved & probable reserves independentlycertified by RPS and current production is approximately 342 bopd. Initial production facilities werecommissioned 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 oilpipeline runs through the licence area for which the Group has negotiated certain access rights. It is theGroup’s intention to build its presence around this area, which is attractive because of its resourcepotential and existing infrastructure.Nine wells had been drilled in the licence area prior to acquisition by the Group. The reservoir is asandstone 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 theGroup has already satisfied). As operator of the licence, the Group has built an operational and technicalteam 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, acquiredcertain early production equipment, drilled three wells and re-entered and brought existing well #226 intoproduction.Capital expenditure in Russia between 2005 and 2007 (IFRS) may be summarised as follows:Nine-month period endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Drilling ................................. — — — 5,590,214Seismic .................................. — 1,345,524 1,373,001 —Other (1) ................................. 6,080,697 11,236,331 4,338,516 8,645,0836,080,697 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 ofapproximately 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 and2010.Independent Reserves at the Zapadno Chumpasskoye FieldRPS estimated the Zapadno Chumpasskoye field’s net working and entitlement interest reserves and valueto the Group as at 30 September 2007, using money of the day prices, discounted at 10 per cent., to beas follows:Net NetNet Working Entitlement PresentInterest Interest ValueMMboe MMboe $MillionsProved ............................................. 23.1 23.1 17.5Probable Additional ................................... 37.4 37.4 209.1Total Proved + Probable ............................... 60.5 60.5 226.6Total Proved + Probable + Possible ....................... 161.4 161.4 762.2The Group’s Russian strategy is to acquire a series of development licences at attractive prices to allow theGroup to generate early cash flow and production. The Group established a jointly owned company withTISE Holding Company, TISE-Heritage Neftegas, in 2007. The other shareholders of TISE HoldingCompany include Concord, Zarubejneft, Zarubejneftegas (a wholly-owned Gazprom subsidiary),Technopromexport and Zarubejstroymontaj. TISE-Heritage Neftegas was formed to appraise and acquireoil and gas opportunities in Russia and internationally.39

OmanThe energy sector of Oman accounts for the majority of its export earnings and government revenue.Oman has current proved hydrocarbon reserves of approximately 5.5 billion bb1s and 795 billion m 3 gaswith current production of approximately 740,000 bopd and approximately 50 million m 3 /day gas. Currentconsumption is some 66,000 bopd and 2.4 million m 3 /day gas. The gas sector in Oman is considered to bethe cornerstone of the government’s economic growth strategy and great efforts have been made to turngas into a thriving export industry and in excess of some 10 billion m 3 are exported annually (all of theabove figures are stated in the CIA World Factbook as at 1 January 2006).Map of Block 8 and West Bukha Field and Surrounding AreaIRANGavarzinSalakhQeshmIslandStraits of HormuzWest BukhaFieldBLOCK 8BukhaFieldMubarek FieldKhor KhwairProcessing PlantOMANRas AlKhaimahLEGENDHeritage PSAOil FieldsU.A.EGas FieldsGas Condensate FieldOil & Gas WellDubaiPipelinesProcessing PlantInternational BorderOMAN0100km14MAR20080054080840

The Group acquired a 10 per cent. interest in Block 8 offshore of Oman in 1996. The other joint venturepartners are RAK Petroleum (the operator) with a 40 per cent. interest and LG International with a50 per cent. interest. This licence has an area of 423 square km and contains the Bukha field which islocated 40 km offshore in the Straits of Hormuz and is a gas-condensate field, in around 90 metres ofwater. The licence also contains the West Bukha discovery. The Group has proved and probable reservesof 1.6 million barrels of oil equivalent of liquids and gas in Oman, independently certified by RPS and netproduction for January 2008 was approximately 109 bopd.The Bukha field commenced production of gas and condensate from two wells in 1994. Wet gas isproduced through an unmanned platform and channelled via a 34 km pipeline to an onshore plant in RasAl 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 onshorein Ras Al Khaimah, operated by the state gas company, Rakgas. There the gas condensate is stored forsubsequent lifting when logistically economic quantities are accumulated and sold to a third party under anannual 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 revenuefrom gas production from the West Bukha field.Block 8 also contains the Hengam/West Bukha discovery, which represents a significant potential futurefield development. The field is partially located in Block 8 in Oman, approximately 20 km from the Bukhafield, 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-Iranborder. This well was a success and tests produced a combined flow-rate from the zones tested (Ilam/Mishrif/Mauddud and Thamama) of approximately 12,750 bopd and 26 MMscf/d. The oil was light(approximately 42 o API).Development of the West Bukha field commenced in 2007 and is ongoing. It is planned to re-enter theWest Bukha 2 well and complete it as a producer. Facilities design work has been concluded and it isplanned to install a platform and pipeline to deliver the petroleum fluids to markets in Ras Al Khaimah viathe 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 summarisedas follows:Year ended Nine-month periods ended31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Drilling .................................... — 3,209,500 2,621,614 749,862Seismic ..................................... — 419,942 332,192 88,897Other ...................................... 398,316 698,157 233,115 1,982,649398,316 4,327,599 3,186,921 2,821,408Independent Reserves at Bukha Field in Block 8RPS estimated the net working interest reserves and net entitlement interest and value to the Company ofWest Bukha and Bukha as at 30 September 2007, using money of the day prices, discounted at 10 per cent.,to be as follows:NetWorking Net NetInterest Entitlement PresentReserves Interest ValueMMboe MMboe $MillionsProved ............................................... 2.4 1.1 12.8Probable Additional ..................................... 2.9 0.5 20.2Total Proved + Probable .................................. 5.3 1.6 33.0Total Proved + Probable + Possible ......................... 10.1 2.5 61.9UgandaSignificant oil exploration began in Uganda in 1997 following the award of an oil and gas licence to theGroup. Assets in the Albert Basin are controlled by the Group and Tullow Oil plc. The Albert Basin islocated on the border with the DRC.41

The Ugandan government has stated that it wishes to achieve early production as a stepping stone toUganda’s economic growth to reduce reliance on imports and there has been some initial discussion aboutan export pipeline to run to Mombasa in Kenya depending on commercial viability. Discovery of a multihundred-million-barreloil or condensate field could justify a pipeline to the Kenyan coast. A smallerdiscovery of hydrocarbons might lead to the establishment of a regional oil and gas industry to displacehigh-cost imported products or to be used for power generation.Map of Blocks 3A and 1 and Surrounding AreaLEGENDSUDANPermitsAlbert GrabenHeritage PSAOil WellsCountry BorderBLOCK 5NeptuneProspectOil FieldBLOCK 1HeritageD. R. C.BLOCK 2TullowBLOCK 3A HeritageUGANDABLOCK 3B OpenBLOCK 3C OpenBLOCK 3D OpenBLOCK 4BDominionBLOCK 4AOpenRWANDA0+++LEGENDLicence BoundaryHeritage PSAInternational Border+B A S E M E N TAlbertGrabenRwenzoriMountainsSemliki+++D. R. C50kmTuraco -3++Block 3ATANZANIABlueMountainsD. R. CONGOUGANDAPelicanProspect+Block + 3C OpenBlock 3D OpenLakeAlbertWaraga-1Ngassa-1Mputa-2Kingfisher-1+B A S E M E N TBlock 3B Open+++Mputa-1Mputa-4Nzizi-1 Mputa-3Nzizi-2+UGANDA14MAR20080110078442

The Group is the operator and has a 50 per cent. interest in two exploration licences in the hydrocarbonsystem in Lake Albert, Uganda. The Group has had interests in Uganda since 1997. The Directors believethat the Albert Basin in Uganda represents an exciting opportunity with a potential to discover significantquantities of oil.The assets in the Albert basin are controlled by the Group and Tullow Oil plc. Eight exploration andappraisal wells have been drilled successfully in the basin since the beginning of 2006 and all haveencountered oil bearing reservoirs with two of the wells testing at over 12,000 bopd. It is currentlyanticipated that potential production could be in excess of 100,000 bopd in the medium-term. The Group isthe 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 theEast African rift valley, straddling the border with the DRC. Approximately 80 per cent. of Block 3Acovers the south-eastern part of Lake Albert and the remainder is found in the onshore Semliki flats areato 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. Block3A, originally encompassing most of the exploration acreage which previously constituted Block 3, wasre-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. inreturn 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 thePSC entered into by the Group with the Government of Uganda on 1 July 2004. Under the terms of thePSC, the Group will act as operator.According to the Block 1 and Block 3A PSC in Uganda, the Government of Uganda may elect to enterinto a joint venture agreement, at any time, for up to 15 per cent. participation in the properties and theassociated production. The Company has not received any indication from the Government of Ugandathat it intends to invoke this election.The Group has agreed to a total minimum contractual work programme comprising the acquisition of atleast 150 km of seismic data and the drilling of up to three exploration wells. The total minimum financialcommitment 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 testedsuccessfully in the Kingfisher well, resulting in an overall cumulative flow rate of 13,893 bopd through aone inch choke.A shallower interval, at a depth of 1,783 metres, was tested successfully in November 2006, producing4,120 bopd over a 10 metre interval. The tested oil was light (approximately 30 o API) and sweet with a lowgas-oil ratio and some associated wax. Flow data from the test indicated that the reservoir had anextremely high permeability of over 2,000 milliDarcies.Three intervals were successfully tested in February 2007, from between 2,260 metres to 2,367 metres andproduced a cumulative flow rate of 9,773 bopd over a total net productive thickness of 44 metres. The oil isof good, quality light (between 30 o and 32 o API) and sweet with a low gas-oil ratio and some associatedwax. 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 whichmulti-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 Pelicanstructures during the summer of 2007. Initial interpretation of the 3D seismic survey confirms that theKingfisher structure has an aerial extent of approximately 45 square km. The data also identifies a numberof appraisal/development targets within the Kingfisher structure for a multi-well drilling programme fromland and on Lake Albert.A 530 km 2D seismic acquisition programme was completed in Block 3A in Lake Albert in the thirdquarter of 2007. This most recent programme supplemented previously acquired 2D seismic surveys andcovered 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, followingthe release of the Nabors 221 rig from neighbouring Block 2. Management expects this land rig to have thecapability to reach the depth of the primary target horizon not reached by previous Kingfisher drilling. Theprevious 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 isplanned to commence in the first quarter of 2009. Expression of interest documents to obtain a bargemounted rig have been issued recently.A 2D seismic survey has been carried out on in Block 1, where relatively shallow structures have beenidentified with associated amplitude anomalies. Oil is known to have migrated into Block 1, as evidencedby the active oil seep within the block located at Paraa. This oil seep together with the presence ofamplitude 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 drillingprogramme to commence in or after the summer of 2008, concentrated on the shallower targets in thesouthern part of the block. A mobile rig has recently been contracted by the operator of the neighbouringlicence 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 endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Drilling ................................. 2,466,385 11,999,638 5,327,637 7,814,808Seismic .................................. 1,059,395 — — 12,720,495Other ................................... 2,123,457 1,665,298 1,171,610 1,543,3425,649,237 13,664,936 6,499,247 22,078,645Independent Resources at Block 3A and 1RPS estimated that the gross risked recoverable contingent and prospective resources in Blocks 3A and 1are as follows:Gross Risked Recoverable Resources (MMstb)p90 p50 p10 Mean280 793 1,731 923The Group has a 50 per cent. working interest. The Government of Uganda has a back-in right whichcould, if exercised, reduce the Group’s working interest to 42.5 per cent.Democratic Republic of CongoThe DRC is located in West and Central Africa. Oil production is located in the western part of thecountry from the restricted Atlantic offshore and adjacent coastal onshore Congo Basin. The Group’sinterests cover the entire area of Lake Albert that lies within the DRC, plus a smaller area onshore to thesouth 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 thegovernment of DRC, which was signed in July 2006. The Group holds a 39.5 per cent. interest in bothblocks, 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 willbe acquired and exploration wells drilled. However, such works will only commence following the receiptof a presidential decree, the timing of which is uncertain.The Group has agreed to a total minimum contractual work programme which includes collecting and reanalysingexisting seismic data, conducting one 400 km and two 200 km seismic surveys, and drilling four44

exploration wells. The total estimated gross financial commitment amounts to $18.6 million spread overthe five year exploration period.Given the proximity of the DRC licences to the Uganda licences in the Albert Basin, there should be costbenefits from sharing certain operating, capital and infrastructure development costs, including thedevelopment and construction of a potential international export pipeline to Mombasa on the east coastof Kenya.Map of Blocks I and II and Surrounding Area22MAR200811412237Iraq and the Kurdistan Region of IraqIraq has the second largest light oil reserves in the world, estimated at 112 billion bbls of oil and 100 trillioncubic feet of gas (as stated in the CIA World Factbook as at 1 January 2006). The KRI is an underexploredarea with potential resources. The area has had political stability and has relatively low securityrisk compared to other areas of Iraq.45

Map of Miran Block and Surrounding Area44º0’0”E 45º0’0”E 46º0’0”EIRANDemir DaghMIRAN36º0’0”NTaq Taq36º0’0”NIsmail 1KirkukBai HassanKhabbazKirkukChemchemalSuleimaniahIRAQI KURDISTANJamburKor Mor35º0’0”NAjeelJudaida 1035º0’0”N50kmHamrinPulkhanaLEGENDGilabat 1QamarChia Surkh 2Oil FieldsGas FieldsInjana 5Gas Condensate FieldProspectIRAQHeritage PSA44º0’0”E 45º0’0”E 46º0’0”E14MAR200800540947The Group was one of the first companies to be awarded a PSC in the KRI. Heritage Middle East, awholly-owned subsidiary of the Company executed a PSC with the KRG over the Miran Block in the KRIon 2 October 2007. The Group has been appointed operator. The licence area covers approximately1,015 square km. The Miran structure itself is in excess of 500 square km in area and the possibility existsfor multiple reservoir targets. It is estimated by the Directors that the structure could contain significantquantities of oil. The Miran structure lies only 55 km from the giant Kirkuk oilfield with remaining reservesthought to be in excess of 10 billion bbls and 30 km from the Taq Taq field on which recent wells havetested 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 PSCsigned with the KRG (without the prior approval of the Iraqi government) is considered to be void by theIraqi government as they have stated it violates the ‘‘prevailing Iraqi law’’. On the basis of KRI legaladvice, 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 jointventure company which shall build, own and operate an oil refinery in the vicinity of the block. Therefinery, which should have a capacity of 20,000 bopd, is scheduled to be operational to designspecification within approximately two years of the signing of the agreement.MaliThe Group is the operator and has the right to earn a 75 per cent. working interest in each of Blocks 7 and11 by financing 100 per cent. of the minimum work programme over the next two years. The blocks cover agross area of over 72,000 square km and are located in the Gao Basin. The Group’s partner is Mali OilDevelopments 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 workprogrammes 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 periodsubject to additional spend commitments of $8 million for the first and $14 million for the second renewalperiod. Block 11 exploration period can be renewed twice for a duration of 3 years for each period subjectto 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 Area14º 12º 10º24º8º 6º 4º 2º0º 20º 4º 6º24ºLEGEND22ºHeritage PSAExploration WellWell & Gas ShowsMALIALGERIA22ºInternational BorderAtouila-120º0 100 200km20º0 50 100mYarba-1Block 7KidalIn Tamat-118º18º16ºMAURITANIATimbuktuTin Bergoui-1GaoBlock 11Ansongo-1Tahabanat-116ºSENEGAL14º12ºKayesGUINEA10º14º 12º 10ºMoptiSègouKoulikoroBamakoSikassoIVORY COAST8º 6º 4º 2ºBURKINA FASOOuagadougouGHANATOGNIGER14ºNiameyBENIN0º 2º 4º12ºNIGERIA10º14MAR200801100947The two licences are located in the Gao Basin, a Mesozoic basin that the Directors consider has geologicalsimilarities to other Mesozoic interior-rift basins within North Africa, such as the Muglad Basin of Sudanand the Doba Basin of Chad, and Tertiary basins such as the Albert Basin of Uganda. Previous seismic dataacquired in Blocks 7 and 11 show the presence of tilted fault-block traps, and indicate up to approximately4 km of sediments in the geological section.MaltaOn 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. Thelicences (Blocks 2 and 7) extend to almost 18,000 square km and are situated approximately 80 km (in thecase of Block 2) and 140 km (in the case of Block 7) from the south-eastern Maltese coastal waters in47

depths of approximately 300 metres. Initial seismic interpretation, based on the current extensive data setof almost 3,500 km acquired after 2000, has identified a variety of potential prospects. Primary targets areLower Eocene and Cretaceous carbonates that are recognised to be major hydrocarbon producing plays inthe central part of the Mediterranean. The licences are under-explored, having had only one well drilled inBlock 2 (Medina Bank 1) in 1980. The well was drilled to a depth of 1,225 metres and failed to reach thetarget 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 OilCorporation of Libya dated 28 February 2008 stating that the Block 7 licence area lies within the Libyancontinental shelf and a portion of this area has already been licensed to Sirte Oil Company. This letter alsodemands that the Group refrain from any activities over or concerning the Block 7 licence area and assertsthe Libyan government’s right to invoke Libyan and international law to protect its rights in the Block 7licence 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 afurther 1,000 km of seismic data and the drilling of one exploration well. The total minimum financialcommitment amounts to $22 million spread over the first three year exploration phase which may then beextended for a further three year period thereafter.Map of Blocks 2 and 7 and Surrounding AreaSICILYSiracusa (Syracuse)TunisTUNISIASfaxLampuko 1Gozo 1Madonna Taz-Zejt 1ST1Naxxar 2MALTA ValettaAqualta 1Tama 1MS-B1 Valetta 1Alexia 1Alexia 2MS-A1Malta 1Medina Bank 1Block 2Block 7Area ofseismic coverageLEGENDBlock boundaryArea of seismic coverageExploration WellOil & Gas showsInternational BorderTarãbulus (Tripoli)A-001-NC146A-001A-NC087B-001-NC0870 50 100km0 50m25LIBYA14MAR200800291616PakistanA wholly-owned subsidiary of the Company was awarded a 60 per cent. participating interest in the SanjawiBlock (number 3068-2) in Zone II (Baluchistan), Pakistan. The onshore exploration licence has a grossarea of 2,258 square km. The exploration licence and PSC were executed on 16 November 2007 and theGroup has been appointed operator. There are two Pakistan-based joint venture partners pursuant to thePSC, Sprint Energy (Pvt) Limited (being a subsidiary of the JS Group, a Pakistan-based financial servicesprovider), and Trakker Energy (Pvt) Limited.48

Pakistan has current proved hydrocarbon reserves of approximately 289 million bbls and 765 billion m 3 gas(as stated in the CIA World Factbook, 2006 estimate), mainly situated in the central and southern parts ofthe Indus Valley, with current production of approximately 68,000 bopd and approximately 3.9 millionm 3 /day gas (as stated in the CIA World Factbook, 2006 estimate), all of which is consumed domestically.An additional 279,000 bopd are imported (as stated in the CIA World Factbook, 2004 estimate).Map of Sanjawi Block (number 3068-2) and Surrounding Area64ºUZBEKISTANDushanbe72ºLEGENDTAJIKISTANCHINAHeritage PSAOil FieldsGas FieldsGas Condensate FieldAFGHANISTANInternational BorderGas pipelineOil pipelineKabulPeshawarIslamabadRefined product pipeline32º0 100 200km0 50 100mPAKISTANLahoreSavi Ragha-1Dhodak32ºKhattanQuettaSanjawiSalsabilMiriwah -1Zarghuri South-1KhattanJandran -1IndusNew DelhiIRANINDIAKarachi24º 24º64º 72º14MAR2008005410977. MANAGEMENT AND EMPLOYEESEmployeesAs 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 thecapability 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 chosenregions to deliver growth in shareholder value.The Group leverages off a highly effective network of influential industry, political and institutionalrelationships. These relationships enable the Group to form strategic alliances which reduce resourcecommitments and lower exploration and development risk, as well as give the Company accessto properties.The Group’s management team has demonstrated its ability to make substantial oil discoveries and its flatand lean structure has enabled the Group to enjoy first-mover advantage in many of its deals and to takeadvantage of interesting opportunities, such as the KRI and the Albert Basin in Uganda.8. SAFETY, ENVIRONMENT, RISK MANAGEMENT AND CORPORATE AND SOCIALRESPONSIBILITYCorporate and Social ResponsibilityThe Group has always been committed to responsible and respectful conduct towards the diversecommunities in which it operates, believing that it is only through such an approach to businessincorporating economic, environmental and social initiatives that the Group’s sustainable development willbe achieved.The Group believes that in order to create long-term value for its stakeholders, partners and employees, itis imperative that it contributes to its adopted communities. Investing in local communities today isincreasingly accepted as a necessary part of doing business, especially in developing economies that lackbasic infrastructures and the capacity to build social capital as this contributes to a healthy and stablebusiness climate.Over the past five years the Group has implemented a wide range of community projects comprising publichealth, education, environmental, public facility, and community relations-based programmes. In all ofthese, the Group’s involvement was not simply to provide funds, but to actively work with the communitiesin order to build trust and ensure that both the needs of communities and those of the Group wereconsidered when the projects were planned. For example, in Uganda the Group has worked closely withlocal communities in Rwebisengo-Bundibugyo District and Buhuka-Hoima District, to build andrehabilitate roads and valley dams, drill community water wells and construct cattle dipping tanks. TheGroup has constructed and repaired fencing around a number of schools such as Makondo Primary Schoolin 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 theGroup tailors a number of its corporate and social responsibility initiatives to be specifically educationoriented,such as examples in Uganda where the Group is building a school and teachers’ residences atBuhuka and the establishment of a Petroleum Institute for higher education collectively with other oilcompanies operating in Uganda. The Group has so far sponsored three undergraduate students for coursesat 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 innature conservation projects. In Uganda, the Group’s employees are involved in a wide variety of fieldbasedprojects including sponsorship of wildlife conservation and investment in transportation by providingfour-wheel drive vehicles and motorcycles for game wardens.From the outset of these programmes, the Group has actively engaged each community and their localgovernment in planning and agreeing the project implementation strategies and timings (the communitiesare involved at the onset of the project so that they have a sense of ownership and are able to continueimplementation of the project on a sustainable basis).Protecting the environmentThe Group is committed to protecting the environment and for every project envisaged having an impacton the environment; an Environmental Impact Assessment is usually conducted, where potential impactsare identified and appropriate mitigation measures are put in place. The mitigation measures are made50

operational by drawing up an Environmental Management Plan, and this is followed by monitoring theeffectiveness of the plans employed to protect the environment or allow its self-renewal.Environmental IncidentsThe Group attaches great responsibility to its emergency response plans which are instituted in case of anyenvironmental incidents. The Directors place considerable confidence in the effectiveness of the Group’senvironmental incident reporting procedures. To date, the Group has not been subject to any materialenvironmental incidents.9. HISTORY AND DEVELOPMENTThe Group was formed in 1992 and HOC was incorporated in 1996. Over the past twelve years, the Grouphas grown through its strategy of focusing on high-impact international opportunities containing multipletargets with the potential for the discovery of significant reserves, achieved through the management oftechnical and political risk, through the geographic spread of licences and the experienced managementteam’s hands-on approach.Relationship with Mr. Anthony BuckinghamAnthony Leslie Rowland Buckingham is a citizen of the United Kingdom, born on 28 November 1951 inLondon, 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 invarious 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 thistime 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 inestablishing 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 andMarine Hydrocarbons Development Limited. The name was changed to Heritage Oil & Gas Limited on10 June 1993.HOC was initially formed to hold certain oil and gas exploration interests in offshore Angola, principallyan interest in a PSC in respect of Block 4 in the Lower Congo Basin, and through ROWAL a joint venturecompany with Ranger, a reversionary interest in the Kiabo oil field owned and operated by the Angolastate oil company, Sonangol.ROWAL was owned 51 per cent. by Ranger and 49 per cent. by HOC. Heritage’s activities were initiallyfunded by share and loan capital provided by Fleming Mercantile Investment Trust plc and PremierOilfields plc in 1992. ROWAL provided certain technical and advisory services to a division of Sonangol toassist Sonangol in the financing, development and operation of the Kiabo oilfield on sub-block 4/26, inreturn for a reversionary 10 per cent. net profits interest in the Kiabo field. The agreement and serviceswere terminated in 1998.ROWAL was forced to abandon certain oil field and drilling equipment at its base at Soyo in northwesternAngola after it was overrun by UNITA rebels who killed a number of locals and expatriates in1993. ROWAL engaged the services of Executive Outcomes, a private military company, which successfullyretrieved the equipment, allowing the exploration work programme to continue. The loan finance toFleming was thereafter repaid.In 1996, Ranger and HOC amended the existing arrangements so that HOC received a 5 per cent. netprofits 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 discoverywhich predated the award of Block 4 to Ranger).51

The Kiame oilfield, offshore Angola operated by Ranger, commenced production in June 1998. Productionfrom the field terminated in April 2002. Heritage held a 5 per cent. net profit interest. Angola is reportedlythe second largest oil producing country in Africa, producing an average of over 1.4 million bbl/d of oil.Association with private military contractorsIn 1993, ROWAL was forced to abandon certain oil field and drilling equipment at Soyo in north-westernAngola, after it was overrun by UNITA rebels who killed a number of locals and expatriates. As a directresult of this loss, Mr. Buckingham together with Eeben Barlow, Lafras Luitingh and Simon Mann becamebusiness 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 AfricanDefence Force and special forces, and the company successfully recovered the equipment ROWAL hadbeen forced to abandon.Following the success of the operation at Soyo, the internationally recognised government of Angolaengaged Executive Outcomes in a contract to re-train certain elements of the Angolan army and support itin 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 andsupport it in defeating the RUF rebels, who were intent on overthrowing the government. The jointco-operation achieved a level of success sufficient to witness the signing of a peace accord and democraticelections held in 1996. The contract was terminated with effect from January 1997 prior to regionalstability forces entering the country. The operations in Angola and Sierra Leone were ExecutiveOutcomes’ 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 andLieutenant Colonel (Retired) Tim Spicer OBE appointed as Chief Executive. Sandline International wasengaged 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 anuprising led by the PNG army by Brigadier Jerry Singirok, operations were terminated and Mr. Spicer wastemporarily detained by an element of the army who were not in agreement with the government’s plan ofhow to conclude the BRA’s insurgency. The government of PNG settled in full with Sandline Internationalfollowing an international arbitration which unanimously found in Sandline International’s favour andconfirmed that a valid contract had been in existence.In 1998, Sandline International was engaged to support the ECOMOG, a West African multilateral armedforce 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 largeareas of the country, leaving the democratically elected government to flee into exile. SandlineInternational provided support and assistance to ECOMOG, undertook humanitarian rescues andsupplied 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 aRoyal Navy frigate. The operations in Sierra Leone ceased in the spring of 1998, Sandline Internationalbecame dormant and the company was dissolved in 2004.Termination of Association with private military contractorsFollowing the cessation of operations and subsequent dissolution of each of Executive Outcomes andSandline 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 failedplot to overthrow President Teodoro Obiang of Equatorial Guinea. Mr. Buckingham has had nosubstantive business contact with Simon Mann since 1998 and no contact of any nature with him since2000. 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 ExecutiveOfficer of Aegis in 2002. Aegis reportedly is a privately owned British security and risk managementcompany with overseas offices in Afghanistan, Bahrain, Iraq, Kenya, Nepal and the United States ofAmerica and provides services to various governments including the United States of America, is securityadvisor 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 orsecurity operations since the spring of 1998.Corporate DevelopmentThe Company is a newly-formed company incorporated in Jersey. The purpose of the Company is to investindirectly (via its indirectly wholly owned subsidiary DutchCo) in the entire issued share capital of HOC. Itis 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 andoutstanding HOC Common Shares.The registered office of the Company is located at Ordnance House, 31 Pier Road, St Helier, JerseyJE4 8PW, Channel Islands and its head office will be at 28-30 The Parade, St Helier, Jersey, JE1 1BGChannel Islands.Chronology of Key EventsThe table below sets out certain significant milestones in the recent history of the Group.DateEvent1992 ........ The Group was founded. HOGL was incorporated in the Bahamas on 14 January 1992as Land and Marine Hydrocarbons Development Limited, which name was changed toHeritage Oil & Gas Limited on 10 June 1993.The Group was initially formed to hold certain oil and gas exploration interests inoffshore Angola, principally an interest in a PSA in respect of Block 4 in the LowerCongo Basin, and through ROWAL a joint venture company with Ranger, areversionary interest in the Kiabo oil field owned and operated by the Angola state oilcompany, 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 toassist Sonangol in the financing, development and operation of the Kiabo oilfield onsub-block 4/26, in return for a reversionary 10 per cent. net profits interest in the Kiabofield. The agreement and services were terminated in 1998.The Group’s activities were initially funded by share and loan capital provided byFleming and Premier Oilfields plc.1993 ........ ROWAL was forced to abandon certain oil field and drilling equipment at its base atSoyo in north-western Angola after it was overrun by UNITA rebels who killed anumber of locals and expatriates.ROWAL engaged the services of Executive Outcomes, a private military company,which successfully retrieved the equipment, allowing the exploration work programmeto continue.1994 - 1996 . . . The Group received a 2.5 per cent. commission amounting to approximately $2 millionrelating to the construction of two production platforms in South Africa for use in theCabinda region, offshore Angola.1996 ........ Ranger and the Group amended the existing arrangements so that the Group receiveda 5 per cent. net profits interest in the Kiame development and a 2 per cent. net profitsinterest in the balance of Block 4 (other than sub-blocks 4/26 and 4/24 containing theKiabo oilfield and another undeveloped discovery which predates the award of Block 4to Ranger).1996 ........ The Group acquired a 10 per cent. interest in Block 8, offshore Oman. This licencecontains the West Bukha field.1997 ........ The Group was awarded a 50 per cent. interest and operatorship of the Kouilouexploration 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 andsubsequently drilled three test wells at the same Turaco drill site, Uganda53

Date1998 ........ The Kiame oilfield, offshore Angola, operated by Ranger, commenced production inJune 1998. Production from the field terminated in April 2002. The Group held a5 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 theCongo 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 andKouakouala B, C and D licences.2001 ........ The Group sold a 50 per cent. working interest in the Uganda Block 3 licence toEnergy 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 theCongo in the first half of 2002 to Maurel & Prom for a consideration of $30 million incash, $5 million in interest bearing convertible debentures in the purchaser and theretention of a 5 per cent. gross override royalty that becomes effective after 67 millionbbls 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 theCongo for $7 million.2004 ........ The Group is awarded a 50 per cent. working interest in Blocks 1 & 3A in Uganda andis appointed operator.2005 ........ The Group acquired a 95 per cent. interest in the Zapadno Chumpasskoye field, inRussia and appointed as operator.2006/07 ...... On 27 March 2006, HOC issued 600 unsecured convertible bonds each with a par valueof $100,000 for aggregate proceeds of $60 million. The bonds had a coupon rate of10 per cent. per annum and a term of five years and one day. At the option of theholders, the bonds were convertible, in whole or in part, into HOC Common Shares ata price of U.S.$18.00 per share at any time during the term of the bonds. HOC had anoption to redeem, in whole or part, the bonds for cash at any time on or before28 March 2007, at 150 per cent. of par value. On 17 January 2007, HOC gave noticethat it had exercised its option to redeem the 550 outstanding unsecured convertiblebonds at 150 per cent. of par value for total proceeds of $82.5 million plus accruedinterest which was paid on 28 March 2007. Fifty of the 600 unsecured convertiblebonds, with a total par value of $5 million, were converted into 277,778 HOC CommonShares 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 wereawarded under a single PSC with the government of the DRC.2006 ........ The Group entered into an agreement with TISE Holding Company to establish ajointly owned company, TISE-Heritage Nefetegas, which was incorporated in 2007 toappraise 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 andZarubejstroymontaj.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 exerciseprice of £0.60 per share. Heritage Congo held a 14 per cent. interest in the NoumbiPermit, in the Congo.2006 ........ At the end of 2006, the West Bukha-2 appraisal/development well test produced acombined flow-rate from the zones tested (Ilam/Mishrif/Mauddud and Thamama) ofapproximately 12,750 bopd and 26 MMscf/d.Event54

Date2007 ........ On 18 January 2007, the Group finalised the statement of adjustments relating to thesale 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 thelicences, 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 theKouakouala B licence in relation to the Mengo field. The Mengo field is notcurrently in production.2007 ........ On 16 February 2007, HOC raised $165 million by completing a private placement ofconvertible bonds. HOC issued 1,650 unsecured convertible bonds, at par, which have amaturity of five years and one day and an annual coupon of 8 per cent. paidsemi-annually. The bonds are convertible into HOC Common Shares at a price of $47per share. HOC had the right to redeem, in whole or part, the bonds for cash at anytime on or before 16 February 2008, at 150 per cent. of par value. HOC did notexercise this right.2007 ........ First production from the Zapadno Chumpasskoye field in Russia commenced on14 May 2007.2007 ........ The Kingfisher deviated well in Block 3A in Uganda was drilled to a total depth of3,195 metres. Drilling was completed in March 2007. Four intervals were testedsuccessfully in the Kingfisher well, resulting in an overall cumulative maximum flowrate of 13,893 bopd. The oil is good quality light (between 30 o and 32 o API) and sweetwith 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 thesouth-west of the KRI. The Group also agreed to be a 50/50 partner with the KRG todesign and build a 20,000 bopd oil refinery in the vicinity of the licence area. HeritageMiddle East has been appointed as Operator.2007 ........ The Group farmed-in to two onshore exploration licences in the Republic of Mali, inNorth-West Africa, with a gross area of over 72,000 square km in November 2007. TheGroup has been appointed as Operator. The Group entered into farm-in agreementswhich contain the right to earn a 75 per cent. working interest in Block 7 and Block 11from Centric Energy Corporation.2007 ........ On 14 November 2007, HOC completed an equity financing, raising gross proceeds ofCdn $181.5 million from the issue of 3,000,000 HOC Common Shares. As part of thesame transaction, the Major Shareholder sold 3,000,000 HOC Common Sharesreducing its interest from 52 per cent. to 32 per cent.2007 ........ On 16 November 2007, the Group was awarded an onshore exploration licence inPakistan, with a gross area of 2,258 square km. The Group has been awarded a60 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 offshoreMalta.2008 ........ A court approved reorganisation of the share capital of HOC by plan of arrangement isproposed for completion on or about 31 March 2008 pursuant to the ABCA. Forfurther detail, refer to Part VIII of this document.Event10. REASONS FOR THE PLAN OF ARRANGEMENT AND LONDON LISTINGThe Directors believe that the reorganisation of the Group, in a tax efficient manner, in accordance withthe terms of the Arrangement Agreement and the admission of the Ordinary Shares to the Official Listand to trading on the main market of the LSE is in the best interests of the Group and holders of securitiesin HOC.Given the geographic spread of the Group’s production, development and exploration licences with a corefocus on Africa, the Middle East and Russia, the Directors believe that it would now be more appropriatefor the Group to be based in Europe, where a substantial number of holders of securities in HOC and mostof 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 andstatus amongst European investors and within the oil and gas sector generally, and will give the Companyaccess 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 assistin 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 businessdays 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 participatingin the Plan of Arrangement such shareholders have been offered Exchangeable Shares of HOC as analternative to exchanging their HOC Common Shares for Ordinary Shares on the effective date of the Planof Arrangement. The TSX has conditionally approved the listing of the Exchangeable Shares on the TSXsubject 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 OrdinaryShares and the Exchangeable Shares in addition to providing a suitable initial trading price for OrdinaryShares on the LSE.At a future date after 12 months from the date of this document, in order to finance the remainder of theoperation expenditures required to bring the initiated oil and gas exploration activities of the Group intofull production the Group is likely to require additional equity and/or debt financing or the sale of noncoreassets. For the purpose of the ‘‘Illustrative Projections of the Group’’ (contained in Part VIII of thisdocument) this additional funding is assumed to be equity finance.11. INTERCORPORATE RELATIONSHIPSThe corporate structure of the Group, on implementation of the Plan of Arrangement, its principal activesubsidiaries and the other entities in which the Group holds a material interest, the percentage ownershipof voting securities in such subsidiaries or other entities and the jurisdiction of incorporation of suchsubsidiaries or other entities is set out in the structure chart below (for more detail on the companies setout below, please refer to Part X ‘‘Additional Information’’).Heritage Oil Limited(Jersey)100% (1)Heritage Oil Corporation(Alberta)100% (2)(3)Heritage Oil & Gas Ltd.(Bahamas)100% 100% 100% 100% 99%Heritage OilInternationalMalta Ltd.(BVI)HeritageEnergyHoldingGesmbH(Austria)CoatbridgeEstates Ltd.(BVI) (6)EagleEnergy(Oman) Ltd.(Isle ofMan) (5)NeftynanayaGeologicheskayaKompaniya(Russia)100% 100% 100% 100% 50%HeritageOil & Gas(U) Ltd.(Uganda) (4)HeritageDRCLimited(Nevis)HeritageEnergyMiddle EastLtd.(Nevis)HeritageMaliBlock 7(Nevis)HeritageMaliBlock 11(Nevis)50%95%TISE-HeritageNeftegaz(Russia)ChumpassNefteDobycha(Russia)17MAR200823583459Notes:(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 ofHeritage Holdings.(4) One common share of Heritage Oil & Gas (U) Ltd. is held by Hansard Trust Company Limited with a Declaration of Trust infavour 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 infavour of HOGL.(6) One common share of Coatbridge Estates Limited is held by Hansard Trust Company Limited with a Declaration of Trust infavour of HOGL.12. EFFECT OF JERSEY DOMICILEThe City CodeThe City Code will apply to the Company, as it applies to companies that have their registered office in theUnited Kingdom, the Channel Islands or the Isle of Man if any of their securities are admitted to tradingon a regulated market in the United Kingdom or any stock exchange in the Channel Islands or the Isleof Man.Accordingly, upon Admission, shareholders of the Company will be afforded the protections provided bythe City Code, in particular the mandatory takeover provisions in rule 9 of the City Code. In the event of atakeover, 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 theoffer relates.Company LawThere are a number of material differences between the Companies Act and the Act which may impactupon the rights of holders of Ordinary Shares or the Exchangeable Shares. The salient differences are setout in more detail in Part X ‘‘Additional Information’’ of this document.However, the Company, through its Articles, has adopted many provisions commonly found in theCompanies Act and the New Companies Act. For example, rights of pre-emption broadly similar to thosecontained in the New Companies Act have been adopted in the Company’s Articles. Details of theseArticles are set out in more detail in section 6.2(e) of Part X of this document.13. ADMISSION AND SETTLEMENTApplication has been made to the FSA for all of the Ordinary and Exchangeable Shares to be admitted tolisting on the Official List and to the LSE for such Ordinary and Exchangeable Shares to be admitted totrading on its main market for listed securities. It is expected that Admission will become effective and thatdealings in the Ordinary Shares will commence by no later than 8.00 a.m. on 31 March 2008 and theExchangeable 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 theCompany to confirm to it that certain conditions imposed by the Regulations are satisfied beforeCRESTCo will admit any security to CREST. It is expected that these conditions will be satisfied in respectof the Ordinary Shares on admission of the Ordinary Shares to the Official List. As soon as practicableafter 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 securitiesthrough CREST, a depositary or custodian can hold the relevant securities and issue dematerialiseddepositary interests representing the underlying securities which are held on trust for the holders of thedepositary interests.As at the date of this document, the directors of HOC are in the process of finalising a depositary interestarrangement with Computershare to facilitate the transfer of Exchangeable Shares between Canada andthe UK. Although at Admission the depositary interest arrangement will not yet be in place, it is expectedthat such arrangement will be implemented shortly after Admission.57

PART II—DIRECTORS, MANAGEMENT AND CORPORATE GOVERNANCE1. DIRECTORS AND SENIOR MANAGEMENTDirectorsName Position TermMichael Hibberd .......... Chairman and Non-Executive Director 2 years, then 3 yearsAnthony Buckingham ....... Chief Executive Officer 2 yearsPaul Atherton ............. Chief Financial Officer 2 yearsGregory Turnbull .......... Non-Executive Director 1 year, then 3 yearsJohn McLeod ............. Non-Executive Director 1 year, then 3 yearsGeneral Sir Michael Wilkes . . . Non-Executive Director 3 years, then 3 years(a) Michael HibberdMr. 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 companysince 1995, prior to which he spent 12 years with Scotia McLeod in corporate finance and held the positionof Director and Senior Vice-President, Corporate Finance. He is also Chairman and co-CEO of SunshineOilsands Ltd. and currently serves on the boards of directors of AltaCanada Energy Corp., ChallengerEnergy Corp., Iteration Energy Ltd., Pan Orient Energy Corp., Ramtelecom Inc. and Zapata EnergyCorporation. Mr. Hibberd also served as a director of Rally Energy Corp. until October 2007 and as adirector of Deer Creek Energy Limited until December 2005. Mr. Hibberd joined HOC in March 2006.(b) Anthony BuckinghamMr. Buckingham is the founder of the Group. Mr. Buckingham commenced his involvement in the oilindustry as a North Sea diver and subsequently became a concession negotiator acting for severalcompanies including Ranger Oil Limited and Premier Oil plc. He was previously a security adviser tovarious governments. Further information on Mr. Buckingham is set out in ‘‘History and Development’’ insection 9 of Part I of this document.(c) Paul AthertonMr. Atherton is a qualified accountant, having qualified with Deloitte & Touche, and holds a degree ingeology from Imperial College London. He has a corporate finance background with specific experience inthe international mining and resource sectors. He joined HOC in 2000 and joined the HOC board ofdirectors in 2005.(d) Gregory TurnbullMr. Turnbull is the Regional Managing Partner of the Calgary office of the law firm of McCarthyTétrault LLP. Mr. Turnbull has extensive knowledge of corporate governance issues and has acted for manyboards 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, hewas a partner with Gowlings LLP (formerly Code Hunter LLP). In 2001 and 2002, he was a partner withthe law firm of Donahue LLP. Mr. Turnbull has been a partner with the law firm of McCarthy Tétrault LLPsince July 2002. He joined HOC in 1997.(e) John McLeodMr. McLeod is a professional engineer with over 36 years of varied resources extraction experience. He isthe President of McLeod Petroleum Consulting Limited, the President, CEO and a director of CaliforniaOil and Gas Corporation and has held positions and has served on various boards including atConstellation Oil & Gas Ltd.; as President and CEO of Arakis Energy Company; as VP, Operations ofPengrowth 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., TuscanyEnergy Ltd., Diaz Resources Ltd. and Keeper Resources Inc. He joined HOC in 1998.58

(f) General Sir Michael WilkesGeneral Sir Michael Wilkes, aged 67, Non-Executive DirectorGeneral Sir Michael Wilkes KCB, CBE, retired from the British Army (the ‘‘Army’’) in 1995 as AdjutantGeneral and Middle East Adviser to the British Government. As Adjutant General, Sir Michael was themost senior administrative officer within the Army and a member of the Army Board. During hisdistinguished career, he has seen active service across the world while also commanding at every level fromPlatoon to Field Army including commanding 22 Special Air Service Regiment and serving as the Directorof 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 holdsnon executive positions on a number of private companies including Britam Defence and Trico Ltd andchairs the Advisory Board of PegasusBridge Fund Management Limited, a homeland security company.He joined the Group on 18 March 2008.Senior ManagerNameNon-ExecutivePositionBrian Smith ...................................................... VP ExplorationBrian SmithMr. Smith has 30 years experience in the oil industry. He initially worked as an exploration geologist forExxon in the North Sea and Gulf of Mexico. He subsequently joined Enterprise Oil where he managedvarious exploration projects in the Far East and Eastern Europe. He joined the Group in 1997.2. EMPLOYEESThe table below sets out the number of people (full-time equivalents) employed by the Group includingexecutive directors of HOC as at 31 December 2007 and 31 December 2006 and 2005:As at31 December 2007 31 December 2006 31 December 2005Total ......................... 89 72 28As at 31 December 2007, the Group had 89 employees (including full-time contractors and consultants, ifany and Mr. Buckingham and Mr. Atherton). 41 employees are based in Russia, 5 employees are based inthe KRI, 14 employees are based in the UK, 4 employees are based in South Africa, 3 employees are basedin Switzerland, 1 employee is based in Canada and 21 employees are based in Uganda.3. MAJOR SHAREHOLDERThe following table contains certain information regarding the Major Shareholder.Number of Ordinary Shares (1) Percentage of Ordinary Shares (2)owned by the Majorowned by the MajorName of Major Shareholder Shareholder ShareholderAlbion 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 notbe possible for investors to enforce judgments against the Major Shareholder which have been obtained inJersey 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 andoutstanding 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 theCompany on 28 March 2008. The relationship agreement’s purpose is to ensure that the Group is capableof carrying on business independently of the Major Shareholder and Mr. Anthony Buckingham (in hiscapacity as a shareholder of the Company) and that transactions and relationships with the Major59

Shareholder and Mr. Anthony Buckingham are at arm’s length and on normal commercial terms. The keyterms and conditions of this agreement are set out in more detail in section 10.4 of Part X ofthis document.4. CORPORATE GOVERNANCEIntroductionThe Directors recognise the importance of maintaining sound corporate governance practices. TheCompany will be in compliance with the corporate governance regime applicable to it as a Jerseyincorporatedcompany. In addition, as its shares will be admitted to listing on the Official List and tradingon the LSE, the Combined Code is also applicable.The Company currently complies with all aspects of the Combined Code except for the recommendationthat at least half of the board of directors of a listed company, excluding the Chairman, should comprisenon-executive directors determined by the board to be independent in character and judgement and freefrom 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 theCompany’s audit committee.As at Admission, only two of the six directors (excluding the Chairman who would also be considered anindependent non-executive for the purposes of the Combined Code), John McLeod and GeneralSir Michael Wilkes, are considered by the Board to be independent according to the criteria of theCombined Code. Gregory Turnbull would not technically be considered to be independent according to thecriteria 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 ofindependence, the Board holds Gregory Turnbull to be independent in character and judgement and tothereby satisfy the Combined Code requirements for independence. In addition, the Chairman and each ofthe other Directors are independent of Anthony Buckingham.Additionally, despite being the Chairman of the Company, Mr Hibberd has been appointed to the AuditCommittee (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 soonas is reasonably practicable after Admission, the directors intend to rectify these deficiencies in theCompany’s compliance with the Combined Code.The Board StructureUpon 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 andGeneral Sir Michael Wilkes are the directors considered by the Board to be independent pursuant to theCombined Code.The Chairman’s role is to ensure good corporate governance. His responsibilities will include leading theBoard, ensuring the effectiveness of the Board in all aspects of its role, ensuring effective communicationwith shareholders, setting the Board’s agenda and ensuring that all Directors are encouraged to participatefully 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 CommitteeThe Audit Committee is chaired by an independent non-executive director, and its other members arecertain other non-executive directors of the Company. The Audit committee will meet not less than twotimes a year and will have responsibility for, amongst other things, monitoring the integrity of theCompany’s financial statements and reviewing its summary financial statements. It will oversee theCompany’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 Codeand the requirements of the Listing Rules. It will also have responsibility for reviewing the effectiveness ofthe Company’s system of internal controls and risk management systems. The ultimate responsibility forreviewing and approving the interim and annual financial statements remains with the Board. Thenon-executive directors of the Company who have been appointed as the initial members of the Auditcommittee are considered by the Board to have recent and relevant financial experience.60

Remuneration CommitteeThe Remuneration Committee is chaired by an independent non-executive director and its other membersare certain other non-executive directors of the Company. The Remuneration Committee will meet notless than at least once a year and will have responsibility for making recommendations to the Board: (i) onthe Company’s policy on the remuneration of Senior Manager and (ii) for the determination, withinagreed terms of reference, of the remuneration of the Chairman and of specific remuneration packages foreach of the Executive Directors and the Senior Manager, including pension rights, and any compensationpayments. The Remuneration Committee will also ensure compliance with the Combined Code inthis respect.Nomination CommitteeThe Nomination Committee is chaired by an independent non-executive director and its other membersconsist of an independent non-executive director and an executive director. The committee will meet atleast once a year and will, with effect from Admission, have responsibility for making recommendations tothe Board on the composition of the Board and its committees and on retirements and appointments ofadditional and replacement Directors and ensuring compliance with the Combined Code.Model CodeUpon 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 withthe Model Code as published in the Listing Rules. The code adopted will apply to the Directors and otherrelevant employees of the Company including the Senior Manager.Remuneration PolicyThe purpose of the Company’s remuneration policy is to enable it to recruit, retain and motivate the bestpeople for the Company. It is the Company’s aim to ensure that there is a clear link between theCompany’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 RemunerationCommittee will review executive and non-executive rewards policies, the total rewards available to theexecutive and non-executive directors and the share-schemes in light of best practice in the U.K. TheCompany expects to seek Shareholder approval for a new performance-related executive incentive schemeat the next annual general meeting. It is the intention of the Company that over time it will provideexecutive rewards in a fashion in line with the Association of British Insurers and the National Associationof Pension Funds guidelines, whilst maintaining an internationally competitive position.61

PART III—TECHNICAL REPORTSet out on the following pages is the statement of reserves data and other oil and gas information in relationto 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 KingdomT +44 (0)1483 746500 F +44 (0)1483 746505 E rpsenergy@rpsgroup.com W www.rpsgroup.com17MAR200823583789The DirectorsHeritage Oil Corporation#260 Petex Building, 600 - 6 Ave SwCalgary,Alberta,Canada, T2P OS5Project Ref: ECV137728 March 2008Gentlemen,EVALUATION OF HERITAGE OIL CORPORATION’S PETROLEUM ASSETSIn response to your request, and the subsequent Letter of Engagement dated December 3 rd 2007, RPSEnergy (‘‘RPS’’) has completed an independent evaluation of certain oil and gas properties in Russia,Oman, Uganda and Kurdistan in which Heritage Oil Corporation (‘‘Heritage’’) has an interest(‘‘the Properties’’). We have estimated a range of reserves and resources as at 30 th September 2007, basedon data and information available up to 31 st December 2007.In estimating resources we have used standard petroleum engineering techniques, which combinegeological and production data with information concerning fluid characteristics and reservoir pressure,where available. We have estimated the degree of uncertainty inherent in the measurements andinterpretation of the data and have calculated a range of reserves and resources and risk factors inaccordance 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 wehave 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 andpresentations pertaining to the contractual and fiscal terms applicable to the assets. In carrying out thisreview RPS has relied solely upon this information.Summary of Reserves and ResourcesReservesTotal gross reserves and net reserves attributable to Heritage’s Properties are summarised in Table 1.United Kingdom | Australia | USA | Canada | Ireland | Netherlands | MalaysiaRPS Energy Limited: Registered in England No. 1465554, Centurion Court, 85 Milton Park, Abingdon, Oxfordshire OX14 4RY, United Kingdom17MAR20082358362563

Heritage Net EntitlementHeritage Net WorkingReserves (at Base CaseGross Remaining Reserves Interest Reserves Price Forecast)Proved Proved Provedplus plus plusProved Probable Proved Probable Proved Probableplus plus plus plus plus plusProved 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 61.6 163.1LPG (MMstb) .... 7.4 14.5 27.9 0.745 1.4 2.8 0.180 0.254 0.388Gas (Bscf) ....... 7.4 47.5 90.0 0.736 4.8 9.0 0.510 1.5 2.3Table 1: Summary of Heritage Reserves as of 30 th September 2007The gross reserves and the net reserves attributable to each Heritage Property is given in Table 2.Heritage NetHeritage EntitlementGross Net Working Reserves atRemaining Interest Base CaseReserves Reserves Price ForecastBukha Field, OmanCondensate MMstb MMstb MMstbProved Reserves (1P) ............................... 2.1 0.206 0.094Proved plus Probable Reserves (2P) .................... 2.4 0.243 0.099Proved plus Probable plus Possible Reserves (3P) .......... 2.6 0.260 0.102LPG MMstb MMstb MMstbProved Reserves (1P) ............................... 1.5 0.151 0.035Proved plus Probable Reserves (2P) .................... 2.2 0.225 0.046Proved plus Probable plus Possible Reserves (3P) .......... 2.5 0.253 0.049West Bukha Field, OmanOil MMstb MMstb MMstbProved Reserves (1P) ............................... 9.1 0.906 0.520Proved plus Probable Reserves (2P) .................... 20.7 2.1 0.764Proved plus Probable plus Possible Reserves (3P) .......... 39.5 3.9 1.2Condensate MMstb MMstb MMstbProved Reserves (1P) ............................... 3.9 0.390 0.195Proved plus Probable Reserves (2P) .................... 8.0 0.794 0.275Proved plus Probable plus Possible Reserves (3P) .......... 16.1 1.6 0.427LPG MMstb MMstb MMstbProved Reserves (1P) ............................... 5.9 0.594 0.145Proved plus Probable Reserves (2P) .................... 12.3 1.2 0.208Proved plus Probable plus Possible Reserves (3P) .......... 25.4 2.5 0.339Gas Bscf Bscf BscfProved Reserves (1P) ............................... 7.4 0.736 0.510Proved plus Probable Reserves (2P) .................... 47.5 4.8 1.5Proved plus Probable plus Possible Reserves (3P) .......... 90.0 9.0 2.3Zapadno Chumpasskoye Field, RussiaOil MMstb MMstb MMstbProved Reserves (1P) ............................... 24.4 23.1 23.1Proved plus Probable Reserves (2P) .................... 63.6 60.5 60.5Proved plus Probable plus Possible Reserves (3P) .......... 169.9 161.4 161.4Table 2: Summary of Reserves for Each Property as of 30 th September 200764

ResourcesA summary of the gross Contingent Resources and the net working interest Contingent Resources inHeritage’s Properties is given in Table 3.HeritageGross Estimate Working Interest Share †(MMstb)(MMstb)1C 2C 3C Equity 1C 2C 3C(Low) (ML) (High) (%) (Low) (ML) (High) OperatorKingfisher, Uganda 17.2 117.9 493.6 50 † 8.6 59.0 246.8 HeritageTotal ..... 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 RPSA summary of the gross Prospective Resources and Heritage’s 50 per cent. equity interest ProspectiveResources (1) that have been reviewed by RPS is given in Table 4 along with the RPS estimate of GeologicalProbability of Success (GPoS),. N.B. The State has the right to back-in for up to 15% which would reducethe Heritage net working interest to 42.5%.Heritage WorkingGross Estimate Interest Share †Low Best High Low Best High GPoS ††(p90) (p50) (p10) Mean (p90) (p50) (p10) Mean (%) OperatorBlock 3A, UgandaKingfisher Main (Basal sand) . . 55 211 698 267 28 106 349 134 35 HeritageKingfisher North (Zone P1/M6) 4 32 97 37 2 16 49 19 43 HeritageKingfisher North (Basal sand) . . 14 56 191 72 7 28 96 36 29 HeritagePelican Main (Zone P1/M6) . . . 12 59 212 77 6 30 106 39 38 HeritagePelican Main (Basal sand) ..... 36 127 387 155 18 64 194 78 29 HeritagePelican North (Zone P1/M6) . . . 0 2 9 3 0 1 5 2 18 HeritagePelican North (Basal sand) .... 1 5 13 5 1 3 7 3 23 HeritagePelican Shallow (Zone P1/M6) . 4 15 47 19 2 8 24 10 18 HeritagePelican Shallow (Basal sand) . . . 6 21 62 25 3 11 31 13 24 HeritagePelican West (Zone P1/M6) . . . 2 11 41 15 1 6 21 8 23 HeritagePelican West (Basal sand) ..... 13 44 129 52 7 22 65 26 23 HeritagePelican (light blue) .......... 10 53 230 78 5 27 115 39 18 HeritagePelican (light green) ......... 10 53 230 78 5 27 115 39 18 HeritageLead A (Zone P1/M6) ....... 5 69 560 153 3 35 280 77 13 HeritageLead A (Basal sand) ......... 22 110 490 169 11 55 245 85 9 HeritageLead B (Zone P1/M6) ....... 14 83 332 114 7 42 166 57 13 HeritageLead B (Basal sand) ......... 6 31 133 46 3 16 67 23 9 HeritageLead C (Zone P1/M6) ....... 68 372 1,338 486 34 186 669 243 12 HeritageLead C (Basal sand) ......... 28 177 1,012 330 14 89 506 165 9 HeritageBlock 1, UgandaBuffalo .................. 111 344 826 420 56 172 413 210 20 HeritageCrocodile ................. 16 31 57 35 8 16 29 18 20 HeritageGiraffe .................. 35 76 161 89 18 38 81 45 20 HeritageHartebeest ................ 8 24 64 31 4 12 32 16 20 HeritageTotal 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 ofcommercial chance of success.††† Arithmetic summation of individual P90, P50 and P10 quantities will not produce a total P90, P50 and P10. The process ofstatistical addition will, as a result of the central limit theorem, produce a P90 that is greater than the arithmetic sum of allP90 quantities and a P10 that is less than the arithmetic sum of all P10 quantities. The arithmetic sum of the mean quantitieshowever 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 willbe 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 andProspective resources in Blocks 1A and 3 have been consolidated stochastically and are quoted on a100 per cent. basis (i.e. gross) in Table 5.Gross Risked Recoverable Resources (MMstb)p90 p50 p10 Mean280 793 1,731 923Table 5:Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPSHeritage has estimated potential resources in areas of their Ugandan blocks beyond seismic control. Thiswas beyond the scope of the RPS evaluation given the time available. Conceptual leads are based onHeritage’s regional and structural knowledge. At the time of this report, Heritage carry three conceptualleads in their portfolio: two of which are located in the northern part of Block 1 and one in the southwesternextremity of Block 3A. The unrisked mean STOIIP estimates from these evaluations are reportedfor completeness (Table 6) but RPS does not warrant these estimates and is not in a position to commenton the hydrocarbon potential of these areas.Mean STOIIP (MMstb)Block 3A, Conceptual Structure D ........... 464Block 1, Conceptual Structure F ............ 2,925Block 1, Conceptual Structure G ............ 2,925Total ........................... 6,314Table 6:Heritage Unrisked Conceptual Leads (Not Reviewed by RPS)Economic EvaluationEconomic valuation of reserves and resources are linked to a long term price forecast for Brent. The BaseCase price forecasts, used for all valuations presented in this report, are given in. Table 7.US$/bbl, MOD4Q 2007 ........................... 88.62008 .............................. 85.02009 .............................. 82.02010 .............................. 80.02011 .............................. 78.02012 .............................. 77.02013 .............................. 77.32014 .............................. 78.82015 .............................. 80.42016 .............................. 82.02017 .............................. 83.72018 .............................. 85.32019 .............................. 87.02020 .............................. 88.82021 .............................. 90.62022 onwards ....................... +2% p.a.Table 7:RPS Price Base Case Forecasts (US$/bbl Money of the Day)66

The post tax Net Present Value (NPV) at various discount rates 4 applying the RPS Base Case priceforecasts are tabulated in Table 8.Post-Tax Net Present ValueEconomic(US$ Million, Money of the Day)Limit (1) 5% 7.5% 10% 12.5% 15%Net Heritage ShareBukha Field, OmanProved Reserves (1P) ...................... 2029 2.2 1.7 1.4 1.2 1.0Proved plus Probable Reserves (2P) ........... 2029 2.8 2.1 1.7 1.4 1.2Proved plus Probable plus Possible Reserves (3P) . . 2029 3.0 2.3 1.7 1.4 1.2West Bukha Field, OmanProved Reserves (1P) ...................... 2037 15.5 13.2 11.4 9.9 8.7Proved plus Probable Reserves (2P) ........... 2037 39.9 35.1 31.3 28.3 25.7Proved plus Probable plus Possible Reserves (3P) . . 2037 79.7 68.6 60.2 53.6 48.3Zapadno Chumpasskoye Field, RussiaProved Reserves (1P) ...................... 2025 69.1 40.2 17.5 0.2 32.9Proved plus Probable Reserves (2P) ........... 2029 413.6 308.0 226.6 163.5 46.7Proved plus Probable plus Possible Reserves (3P) . . 2031 1356.2 1013.7 762.2 574.5 238.2Note(1) Economic limit represents last year of input forecast production.Table 8: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves as of 30 th September 2007The only 1C, 2C and 3C contingent and prospective resources in the portfolio are in Block 1 and 3A,Uganda and, at the request of Heritage, were not valued.Heritage was awarded a PSC for the Miran block in Kurdistan on 2 nd October 2007. There is insufficientdata to estimate volumes of prospective resources in Miran at this stage. However in order to indicatepossible value of the block RPS has, based on its detailed understanding of fields in the vicinity, made anestimate of the relationship between field size and value in the success case. Based on a low-mid-highrange of 900 1,950 3,500 MMstb notional STOIIP, RPS has developed production and cost profilesand a relationship between field size and value in the success case. Average success case NPV 10 perrecoverable barrel is given in Table 9:Miran ........................Table 9:Value (NPV 10 )per recoverable barrelUS$2.6Success Case NPV 10 US$/per Recoverable Barrel (p50 case)QualificationsRPS 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 commercialarrangement 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 withinternational consultancies. He is a Member of the Society of Petroleum Engineers and a Fellow of theEnergy Institute, as well as being a Chartered Petroleum Engineer. Other RPS Energy employees involvedin this work hold at least a Masters degree in geology, geophysics, petroleum engineering or a relatedsubject or have at least five years of relevant experience in the practice of geology, geophysics or petroleumengineering.Basis of OpinionThe evaluation presented herein reflects our informed judgement based on accepted standards ofprofessional investigation, but is subject to generally recognised uncertainties associated with theinterpretation of geological, geophysical and engineering data. The evaluation has been conducted within67

our understanding of petroleum legislation, taxation and other regulations that currently apply to theseinterests. However, RPS is not in a position to attest to the property title, financial interest relationships orencumbrances related to the properties. RPS can not opine on the agreements between Oman and Iranconcerning the development of the West Bukha Field. Our estimates of reserves and resources and valueare based on the data set available to, and provided by Heritage. We have accepted, without independentverification, the accuracy and completeness of these data.The report represents RPS’s best professional judgement and should not be considered a guarantee orprediction of results. It should be understood that any evaluation, particularly one involving explorationand future petroleum developments may be subject to significant variations over short periods of time asnew information becomes available. This report relates specifically and solely to the subject assets and isconditional upon various assumptions that are described herein. This report must, therefore, be read in itsentirety. This report was provided for the sole use of Heritage and its advisors on a fee basis. This reportmay be reproduced or redistributed to any other persons in its entirety. However in instances whereexcerpts only are to be reproduced or published, other than in relation to the initial public offering, thiscannot 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 includedwithin it and with inclusion therein of its report and references thereto. RPS accepts responsibility for theinformation contained in the RPS report set out in this part of this document and to the best knowledgeand belief of RPS, having taken all reasonable care to ensure that such is the case, the informationcontained in such report is in accordance with the facts and does not omit anything likely to affect theimport of such information.Yours faithfully,RPS Energy27MAR200808225692EurIng Roy T. Kelly, CEng, FEITechnical Director68

RPS EnergyHeritage Oil – Competent Persons ReportTABLE OF CONTENTS1. DESCRIPTION OF ASSETS ................................................ 741.1. Overview ........................................................... 741.2. Liabilities .......................................................... 772. METHODS USED IN THIS REPORT ......................................... 772.1. General ............................................................ 772.2. Reserves and Resource Classification ...................................... 772.3. Risk Assessment ..................................................... 772.3.1. Contingent Resources ............................................. 772.3.2. Prospective Resources (Exploration Prospects) ........................... 782.4. Uncertainty Estimation ................................................. 783. OMAN BLOCK 8 ........................................................ 783.1. Overview ........................................................... 783.2. Bukha Field ......................................................... 793.2.1. Database ...................................................... 793.2.2. Geology and Geophysics ........................................... 793.2.3. In Place Volumes ................................................ 803.2.4. Petroleum Engineering ............................................ 803.2.5. Interaction with the West Bukha Field ................................. 823.3. West Bukha Field ..................................................... 833.3.1. Database ...................................................... 833.3.2. Geology & Geophysics ............................................ 833.3.3. In Place Volumes ................................................ 853.3.4. Petroleum Engineering ............................................ 874. ZAPADNO CHUMPASSKOYE ............................................... 934.1. Data Available ....................................................... 944.2. Geology ............................................................ 944.2.1. Regional Setting ................................................. 944.2.2. Zapadno Chumpasskoye Field ....................................... 944.2.3. Petrophysics .................................................... 954.3. In Place Volumes ..................................................... 974.4. Petroleum Engineering ................................................. 984.4.1. Reservoir Fluid Properties .......................................... 984.4.2. Well Performance & Deliverability .................................... 984.4.3. Development Plan (Subsurface) ...................................... 994.4.4. Recovery Mechanisms ............................................. 1004.4.5. Production Profiles ............................................... 1014.5. Facilities and Costs ................................................... 1055. UGANDA—BLOCKS 1 & 3A ................................................ 1055.1. Overview ........................................................... 1055.2. Data Available ....................................................... 1055.3. Geological Setting .................................................... 1065.4. Geology & Geophysics ................................................. 1075.4.1. Kingfisher 1 .................................................... 1075.4.2. Mapping ....................................................... 1095.4.3. Prospectivity .................................................... 1095.5. Volumetrics ......................................................... 1105.6. Other Prospectivity ................................................... 1135.7. Petroleum Engineering ................................................. 1145.7.1. Production Profiles for Kingfisher and Other Block 3A Prospects .............. 1145.7.2. Production Profiles for Block 1 Prospects ............................... 115Page69

RPS EnergyHeritage Oil – Competent Persons ReportPage6. KURDISTAN—MIRAN BLOCK ............................................. 1166.1. Data Available ....................................................... 1166.2. Geology ............................................................ 1166.3. In place volumes ..................................................... 1166.4. Reservoir Engineering ................................................. 1176.5. Facilities and Costs ................................................... 1187. ECONOMICS ........................................................... 1187.1. Valuation Assumptions ................................................. 1187.1.1. General ....................................................... 1187.1.2. Oil Prices ...................................................... 1197.2. Valuation Methodology ................................................. 1207.2.1. Reserves ....................................................... 1207.2.2. Contingent and Prospective Resources ................................. 1207.2.3. Other (Miran) ................................................... 1207.3. Oman—Block 8 ...................................................... 1207.3.1. Fiscal Regime and Contract Terms .................................... 1207.3.2. Price Assumptions ................................................ 1207.3.3. Unrecovered Costs ............................................... 1217.3.4. Valuation Summary—Bukha ......................................... 1217.3.5. Valuation Summary—West Bukha .................................... 1227.3.6. Sensitivity to Oil Price ............................................. 1227.4. Russia—Zapadno Chumpasskoye ......................................... 1237.4.1. Fiscal Regime and Contract Terms .................................... 1237.4.2. Price Assumptions ................................................ 1247.4.3. Transportation Costs .............................................. 1247.4.4. Tax Losses ..................................................... 1247.4.5. Valuation Summary ............................................... 1247.4.6. Sensitivity to Oil Price ............................................. 1257.5. Kurdistan—Miran Block ............................................... 1257.5.1. Fiscal Regime and Contract Terms .................................... 1257.5.2. Price Assumptions ................................................ 1257.5.3. Valuation summary ............................................... 126APPENDIX A: GLOSSARY OF TECHNICAL TERMS ............................... 127APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS .............. 12970

RPS EnergyHeritage Oil – Competent Persons ReportList of FiguresFigure 1: Omani Licence Location Map ........................................ 75Figure 2: Russian Licence Location Map ....................................... 75Figure 3: Kurdistan Licence Location Map ...................................... 76Figure 4: Ugandan & DRC Licences Location Map ............................... 76Figure 5: Bukha Field—Top Reservoir Depth Map ................................ 79Figure 6: Bukha Wet Gas History and Forecast .................................. 81Figure 7: Condensate Yield vs. Cumulative Wet Gas Production ...................... 82Figure 8: LPG yield vs. Cumulative Wet Gas Production ............................ 82Figure 9: Top Mishrif Depth Map ............................................ 84Figure 10: West Bukha 3D inline 1122 .......................................... 85Figure 11: 1P Production Profile for West Bukha .................................. 92Figure 12: 2P Production Profile for West Bukha .................................. 92Figure 13: 3P Production Profile for West Bukha .................................. 93Figure 14: Lower J 1 Sand—RPS Net Pay Map (p50 Case) ............................ 95Figure 15: CPI for Well P3 over Reservoir Interval for p50 Saturation Case ............... 97Figure 16: Well 226 Production History ......................................... 98Figure 17: Well P3 Production History .......................................... 99Figure 18: Illustration of Inverted Five-spot Patterns at Zapadno Chumpasskoye ........... 100Figure 19: Oil Rate & Cumulative from Full Field Simulation ......................... 101Figure 20: Water Injection Rate & Cumulative from Full Field Simulation ................ 101Figure 21: Average Reservoir Pressure from Full Field Simulation ...................... 102Figure 22: 1P Production Profile for Zapadno Chumpasskoye ......................... 103Figure 23: 2P Production Profile for Zapadno Chumpasskoye ......................... 103Figure 24: 3P Production Profile for Zapadno Chumpasskoye ......................... 104Figure 25: Seismic Section through Kingfisher 1 Well ............................... 107Figure 26: Reservoir Section in Kingfisher 1A .................................... 108Figure 27: RPS Cycle P1/M6 Depth Map, Block 3A ................................ 108Figure 28: RPS Top Reservoir Depth Map, Block 1 ................................ 110Figure 29: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewedby RPS (MMstb) ................................................ 113Figure 30: Generic, Scalable Profile for Block 3A Prospects .......................... 115Figure 31: Generic, Scalable Profile for Block 1 Prospects & Leads ..................... 115Figure 32: Assumed Well Profiles for Miran Wells ................................. 118Figure 32: RPS Base Forecast Price ............................................ 119Figure 33: Plot of Brent vs. URALS (Mediterranean)—1997 to 2007 .................... 124Figure 34: Heritage Net NPV 10 vs. Notional Field Size Showing Price Sensitivity ........... 126Page71

RPS EnergyHeritage Oil – Competent Persons ReportList of TablesTable 1: Summary of Heritage Reserves as of 30 th September 2007 .................... 64Table 2: Summary of Reserves for Each Property as of 30 th September 2007 .............. 64Table 3: Summary of Contingent Resources Reviewed by RPS ........................ 65Table 4: Summary of Prospective Resources Reviewed by RPS (MMstb) ................ 65Table 5: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewedby RPS ....................................................... 66Table 6: Heritage Unrisked Conceptual Leads (Not Reviewed by RPS) ................. 66Table 7: RPS Price Base Case Forecasts (US$/bbl Money of the Day) .................. 66Table 8: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves as of30 th September 2007 .............................................. 67Table 9: Success Case NPV 10 US$/per Recoverable Barrel (p50 case) ................... 67Table 10: Summary of Heritage’s Properties ...................................... 74Table 11: Range of GIIP for the Bukha Field (Full Field Interest)—from Novus VolumetricsStudy February 2003 .............................................. 80Table 12: West Bukha Volumetric Input Parameters ................................ 87Table 13: West Bukha In place Volumes 100 per cent. Basis .......................... 87Table 14: Summary of West Bukha & Henjam Well Tests ............................ 88Table 15: Initial Composition of West Bukha Wellstream ............................ 89Table 16: Estimated Product Yields from West Bukha Wellstream ...................... 91Table 17: Lower J 1 Sand Input Parameters ....................................... 97Table 18: Zapadno Chumpasskoye, Lower J 1 Sand STOIIP Estimates (MMstb) ............ 97Table 19: The p90 and p50 Drilling Schedule for Zapadno Chumpasskoye ................ 102Table 20: Summary of Results for Zapadno Chumpasskoye ........................... 104Table 21: Uganda Volumetric Input Parameters ................................... 111Table 22: Kingfisher Discovery—STOIIP and Contingent Resource Estimate (100 per cent.Basis) ......................................................... 111Table 23: Block 1 & 3A—STOIIP and Prospective Resource Estimates (On-block, 100 per cent.Basis) ......................................................... 112Table 24: Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewedby RPS ....................................................... 113Table 25: Heritage Conceptual Leads Mean Un-Risked STOIP (100 per cent. Basis) NotReviewed by RPS) ............................................... 114Table 26: Summary of Kingfisher-1A Well Tests ................................... 114Table 27: Summary of Kingfisher-1 Fluid Properties ................................ 114Table 28: Assumptions Used For Profiles ........................................ 114Table 29: Miran Field—Range of Notional STOIIP ................................ 116Table 30: Assumptions Used in Miran Profiles .................................... 117Table 31: RPS Forecast Price Cases ............................................ 119Table 32: Table of Base Case Forecast Prices ..................................... 120Table 33: Bukha Post-Tax Valuation (Net Heritage Share) ............................ 121Table 34: Bukha Reserves Summary ............................................ 121Table 35: West Bukha Post-Tax Valuation (Net Heritage Share) ........................ 122Table 36: West Bukha Reserves Summary ........................................ 122Table 37: Sensitivity of Bukha NPV 10 to Oil Price .................................. 122Page72

RPS EnergyHeritage Oil – Competent Persons ReportPageTable 38: Sensitivity of West Bukha NPV 10 to Oil Price .............................. 123Table 39: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share) ............... 124Table 40: Zapadno Chumpasskoye Reserves Summary .............................. 125Table 41: Sensitivity of Zapadno Chumpasskoye NPV 10 to Oil Price ..................... 125Table 42: Net NPV 10 and Average for NPV 10 /stb for a Range of Notional Field Sizes ........ 12673

RPS EnergyHeritage Oil – Competent Persons Report1. DESCRIPTION OF ASSETS1.1. OverviewHeritage has a portfolio of assets that include production in Oman (Bukha) and Russia (ZapadnoChumpasskoye), undeveloped discoveries in Oman (West Bukha) and Uganda (Kingfisher) and anexploration portfolio including Uganda and Kurdistan and new exploration licences in Mali, Maltaand Pakistan.Details of the assets, provided by Heritage, are summarised in Table 10, below:Licence Area (sq km) Date Awarded Heritage Equity PartnersOMANBlock 8 ....... 423.00 April 1985 10% Rak Petroleum, LGRUSSIAZapadno 195.65 September 1999 95%ChumpasskoyeUGANDABlock 1 † ....... 3,659.00 July 2004 50% Tullow OilBlock 3A † ..... 2,024.50 September 2004 50% Tullow OilKURDISTANMiran Block †† . . . 1,015 .00 October 2007 100%D.R. CONGOBlock I ....... 3,825.00 Signed July 2006 39.5% Tullow Oil,(awaiting Presidential Decree)CohydroBlock II ....... 2,634.00 Signed July 2006 39.5% Tullow Oil,(awaiting Presidential Decree)CohydroMALIBlock 7 ....... 39,804.00 July 2006 75% Centric EnergyBlock 11 ...... 32,810.00 June 2005 75% Centric EnergyMALTAArea 2 ........ 9,190.00 December 2007 100%Area 7 ........ 8,778.00 December 2007 100%PAKISTANSanjawi 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 workinginterest to 42.5%.†† The government has the right to back-in for up to 25% which would reduce the Heritage net workinginterest to 75%.Table 10:Summary of Heritage’s PropertiesAs the licences in Malta, Mali and Pakistan were signed after the effective date of this report, only theproperties in Oman, Russia, Uganda and Kurdistan were reviewed by RPS for this report.74

RPS EnergyHeritage Oil – Competent Persons ReportLocations of the properties are shown in Figure 1 to Figure 4.Figure 1:Omani Licence Location Map21FEB200823161520Figure 2:Russian Licence Location Map21FEB20082316233375

RPS EnergyHeritage Oil – Competent Persons Report21FEB200823153649Figure 3:Kurdistan Licence Location MapBLOCK 5NeptuneDEMOCRATIC REPUBLICBLOCK 1HeritageOF CONGOBLOCK ITullowNgassa-1Waraga-1BLOCK 2TullowBLOCK IITullowMputa-2Mputa-1Mputa-40100kmKingfisher-1Mputa-3Nzizi-1Nzizi-2LEGENDPermitsBLOCK IIIOpenBLOCK 3A HeritageBLOCK 3B OpenBLOCK 3C OpenHeritage PSABLOCK 3D OpenAlbert GrabenCountry BorderBLOCK IVOpenBLOCK 4A OpenUGANDAOil WellBLOCK VDominionBLOCK 4B Dominion25MAR200814223227Figure 4:Ugandan & DRC Licences Location Map76

RPS EnergyHeritage Oil – Competent Persons Report1.2. LiabilitiesThe work programmes associated with the PSAs in Uganda and Kurdistan are discussed in Section 7. Inaddition to the exploration work programme in the Kurdistan PSA, there is also a commitment to build asmall refinery, which should have a capacity of 20,000 barrels of oil per day, in strategic partnership withthe Kurdistan Regional Government (KRG). Heritage has advised that the refinery is scheduled to beoperational to design specification within approximately two years. RPS has not considered the costliability or potential revenues from this refinery project in the notional evaluation of Miran.2. METHODS USED IN THIS REPORT2.1. GeneralThe evaluation presented in this Competent Persons Report (‘‘CPR’’) has been conducted within ourunderstanding of petroleum legislation, taxation and other regulations that currently apply to theseinterests. RPS is not in a position to attest to the property title, financial interest relationships orencumbrances related to the properties.Our estimates of potential resources and risks are based on the limited data set available to, and providedby, Heritage. We have accepted, without independent verification, the accuracy and completeness ofthese data.Volumes and risk factors are presented in accordance with the 2007 SPE/WPC/AAPG/SPEE PetroleumResource Management System (See Section 2.2).2.2. Reserves and Resource ClassificationReserves or resources are estimated according to the 2007 SPE/WPC/AAPG/SPEE Petroleum ResourceManagement System (PRMS). The PRMS Definitions are summarised in Appendix B.In estimating reserves and resources we have used standard petroleum engineering techniques. Thesetechniques combine geological and production data with detailed information concerning fluidcharacteristics and reservoir pressure. RPS has estimated the degree of uncertainty inherent in themeasurements and interpretation of the data and has calculated a range of recoverable reserves. RPS hasassumed that the working interest in each asset advised by Heritage is correct and RPS has not investigatednor 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 thereforeimprecise and depend to some extent on interpretations, which may prove to be inaccurate. Estimates thatwere reasonable when made may change significantly when new information from additional explorationor appraisal activity becomes available.2.3. Risk AssessmentFor all prospects and appraisal assets estimates of the commercial chance of success for ContingentResources and estimate of geological chance of success for Prospective Resources have been made. InPRMS 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 ofSuccess (GPoS) in this document synonymously with Chance of Discovery.2.3.1. Contingent ResourcesThe chance of success in this context means the estimated chance, or probability, that the volumes will becommercially extracted.A Contingent Resource includes both proved hydrocarbon accumulations for which there is currently nodevelopment plan or sales contract and proved hydrocarbon accumulations that are too small or are inreservoirs that are of insufficient quality to allow commercial development at current prices. As a result theestimation of the chance that the volumes will be commercially extracted may have to address bothcommercial (i.e. contractual or oil price considerations) and technical (i.e. technology to address lowdeliverability reservoirs) issues.77

RPS EnergyHeritage Oil – Competent Persons Report2.3.2. Prospective Resources (Exploration Prospects)Unlike risk assessment for Contingent Resources, when dealing with undrilled prospects there is a moreaccepted industry approach to risk assessment for Prospective Resources. It is standard practice to assign aGeological 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 byconsidering both a Play Risk and a Prospect Risk. The chance of success for the Play and Prospect aremultiplied together to give a Geological Probability of Success (GPoS). We consider three factors whenassessing 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 volumeswithin the range defined (Section 2.4). It is not an estimation of commercial chance of success.2.4. Uncertainty EstimationThe estimation of expected hydrocarbon volumes is an integral part of the evaluation process. It is normalpractice to assign a range to the volume estimates because of the uncertainty over exactly how large thediscovery or prospect will be. Estimating the range is normally undertaken in a probabilistic way (i.e. usingMonte 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 andmodel uncertainty.Volumetric input parameters, Gross Rock Volume (GRV), porosity, N:G ratio, S w , fluid expansion factor(Eo or Eg) and recovery factor, are considered separately. RPS has internal guidelines on the best practicein characterising appropriate input distributions for these parameters.Systematic bias in volumetric assessment is a well-established phenomenon. There is a tendency toestimate parameters to a greater degree of precision than is warranted (2) and to bias pre-drill estimates tothe high side (3) . Rose and Edwards (3) observe the tendency towards assessing volumes in too narrow arange, with overly large low-side and mean estimates. RPS uses benchmarked p10/p90 ratios and knownfield-size distributions to check the reasonableness of estimated volumes.3. OMAN BLOCK 83.1. OverviewHeritage via Eagle Energy (Oman) Ltd holds a 10 per cent. equity in one licence (Block 8) situatedoffshore Oman. This licence was acquired in 1996 and contains the currently producing Bukha Field andthe undeveloped West Bukha/Henjam discovery.This block is in a region of complex structures with a multiphase compressional origin. Deformation beganin 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 occurin structures which all have the form of anticlines related to backthrusts that probably originated inadvance of the Semail ophiolite overthrust, but were modified by continued thrusting and wrench faultmovement in the mid Miocene.The reservoirs are shelf limestones of early to mid Cretaceous age. The Aptian age Thamama Grouplimestones are sealed by Albian Nahr Umr Formation shales. These units are followed by a further seriesof 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 thisunconformity increases towards the main thrust front in onshore Oman (hence the younger reservoirs aremissing in the Bukha areas towards the west). This erosive phase was followed, firstly by the transgressiveLaffan shale, and then by the shallow water carbonate Ilam Formation. Both formations are ofConiacian-Santonian age.Late Cretaceous sedimentation was in a foredeep west of the thrust front, in which the Aruma Groupflysch was deposited. Phases of structural growth continued in the Palaeocene, Oligocene and LateMiocene. The Miocene unconformity is particularly strongly developed, and is locally highly angularshowing 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, AAPGBulletin, 84(13)78

RPS EnergyHeritage Oil – Competent Persons Report3.2. Bukha FieldThe Bukha gas field is located in the Straits of Hormuz approximately 12 km off the west coast of theMusandam Peninsula. The field was discovered by IPC in 1979. Three wells have been drilled on thestructure. Bukha-1 and Bukha-2 are situated close to the crest of the structure. Bukha-3 was drilleddirectionally from the Bukha-1 surface location down flank to the southwest. The field has been onproduction from two wells, Bukha-1 and -2, since 1994.3.2.1. DatabaseThe Bukha Field is covered by 2D seismic data that was acquired over a considerable span of time from1974 to 1986. These data have been the subject of a reprocessing exercise in 2001. Despite thisreprocessing numerous problems still exist of the type to be expected with 2D data in areas of high dipsnamely migration misties, out of plane reflections etc. A 3D survey was acquired during 2006/07, but is stillbeing processed by the operator.Production data from the field were provided by Heritage.3.2.2. Geology and GeophysicsThe field consists of a single contiguous NE-SW trending fault and dip closed structure covering an area ofapproximately 35 sq km. The tilted fault block is controlled by two main faults; the Tibat thrust and theBukha back-thrust. Fractured carbonate reservoirs within the Cretaceous Mauddud and ThamamaFormations occur at depths of between 2,900 and 3,500 m TVDSS. The Mauddud Formation has anaverage thickness of 52 m and is separated from the underlying Thamama Formation by the Nahr Umrshale 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 thenorth of the North Bukha fault is known as North Bukha and it is not known whether this area is beingdrained by the production wells. If it becomes apparent that the reserves in the North Bukha area are notbeing produced then an appraisal well may be drilled.Figure 5:Bukha Field—Top Reservoir Depth Map21FEB20082315000779

RPS EnergyHeritage Oil – Competent Persons ReportIn previous reserves reports for Heritage, RPS has reviewed the geology of the field. As no new geologicalor 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 rapidlateral velocity changes over the interval sea level to Top Ilam/Mauddud. The reasons for these velocityvariations are not precisely understood and would appear to be a complex interplay of several contributingfactors. To account for these velocity variations a number of different depth conversion methodologieshave been utilised to generate a range of possible structures and the resulting maps have been used togenerate 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 hundredmetres), 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 arelayered, 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 tighterthan 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, andtherefore may be laterally continuous. The lower is better developed, and is located at the top of theMauddud. 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 commercialflow rates. Fractures appear to be rarely sampled in cores, but are believed to be pervasive. Two issuesconcerning fractures are: 1) whether there is connectivity through the fractures between the verticallystacked 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 eachother 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 VolumesProduction comes from both the Mauddud and the Thamama Formations, each of which should be treatedas an individual reservoir. In addition to the sensitivity provided by the range of GRVs described aboveseveral other factors affect the possible range of reserves in the Bukha Field. The most important of theseare the porosity cut-off used to define net reservoir and the GWCs assumed. None of the wells in the fieldintersects a GWC and therefore it is only possible to establish a lowest known gas level that can be used asa minimum case. The structural spill point can be used as a maximum case. The field operator (currentlyRak Petroleum PCL) carried out a volumetric evaluation to determine the range of possible GIIP values in2003. These were reviewed by RPS in the 2006 reserves review and they appear to a reasonable attempt tocapture the range of uncertainty. There have been no new data to revise these estimates.GIIP (Bscf)Reservoir p90 p50 p10Mauddud ....................................................... 110 182 284Thamama ....................................................... 143 231 330Total ....................................................... 297 417 565N.B. The totals are the p90, p50 and p10 of the stochastically consolidated distributionsTable 11: Range of GIIP for the Bukha Field (Full Field Interest)—from Novus Volumetrics Study February 20033.2.4. Petroleum Engineering3.2.4.1. Reservoir Temperature, Pressure and Gas PropertiesReservoir 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). Historicproduction data indicate that the field came off a plateau (of about 43 MMscf/d) in 2003 and average wetgas rates in 2007 were around 23.3 MMscf/d. The condensate yield from the field was initially above100 stb/MMscf. As the field is produced by depletion only (i.e. without pressure support) the yield has80

RPS EnergyHeritage Oil – Competent Persons Reportsteadily declined and during 2007 the average condensate yield was 40.9 stb/MMscf, while the LPG yieldhas increased to 27.2 stb/MMscf in 2007.3.2.4.2. DevelopmentThe 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’’ flexibleflow line of 1.2 km. The platform is connected to the onshore gas processing plant via a 16’’ carbon steelpipeline of 34 km.Cumulative production to the end of 2007 was approximately 199 Bscf reservoir gas, 13.1 MMstbcondensate and 4.5 MMstb LPG.3.2.4.3. Production ForecastsTo obtain a forecast for wet gas this year, the 2007 monthly data from January up to September 2007 wereused. RPS had no data for the subsequent months. The historic data suggests a clear decline in the gasproduction. However, field performance has exceeded RPS’s previous forecast (for 2006 year-endreserves). 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).60Wet Gas Rate - HistoryWet gas rate 2007501P Forecast2P ForecastWet Gas Rate (MMscf/d)4030203P ForecastDec-071001998 2000 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019Figure 6: Bukha Wet Gas History and Forecast21FEB200823144965Condensate Gas Ratio (CGR) plotted against cumulative wet gas shows how the condensate yield changesalong with the field production. A clear and unique trend was visible in line with expected behaviour and itis been used for the 1P, 2P and 3P cases (Figure 7).81

RPS EnergyHeritage Oil – Competent Persons ReportWet Gas Rate (MMscf/d)706050403020Wet Gas Rate - HistoryWet gas rate 2007October 2007 cut offCondensate YieldCondensate yield 2007Condensate match140120100806040Condensate yield (bbls/MMscf)HistoryForecast1020000 50 100 150 200 250 300Cumulative Gas (Bscf)Figure 7: Condensate Yield vs. Cumulative Wet Gas Production21FEB200823150473In order to create a LPG forecast, a plot of LPG yield vs. cumulative wet gas was inspected (Figure 8). Inprevious years, the historical data appeared to be following a quite steady line, but in recent years it hascome to follow the typical behaviour of C 3 and C 4 fractions in a typical gas condensate reservoir. Apolynomial equation was fitted to the historical data for the 1P case and another polynomial equation wasfitted for the 2P and 3P cases.LPG is split into its components C 3 and C 4 based on sales statements from 2007, that being 43 per cent. forpropane and 57 per cent. for butane.6035503025Wet gas rate (MMscf/d)40302010Wet Gas Rate - HistoryWet gas rate 2007October cut offLPG Yield1P Forecast2P & 3P ForecastHistoryForecast2015105LPG yield (bbls/MMscf)000 50 100 150 200 250 300Cumulative wet gas (Bscf)Figure 8: LPG yield vs. Cumulative Wet Gas Production21FEB2008231538503.2.5. Interaction with the West Bukha FieldAfter 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 to82

RPS EnergyHeritage Oil – Competent Persons Reportflow against the higher back-pressure. The forecast for the West Bukha production start-up has beenassumed, conservatively, by RPS to be January 2009 although the Operator has advised Heritage thatproduction is targeted for 3 rd Quarter 2008. It has been assumed that Bukha will cease productiontemporarily while West Bukha pressures remain high.West Bukha will reach a point when the flowing pressure will be sufficiently low that the Bukha field wouldbe brought back into production and both fields would produce at the same time through the samepipeline to the Ras Al Khaimah Gas Commission (‘‘RAKGAS’’) plant.3.3. West Bukha FieldThe West Bukha/Henjam gas field is located in the Straits of Hormuz approximately 22 km west of theBukha field in about 90m of water. The field straddles the border between Iran and Oman. The field wasdiscovered in 1975 by the Henjam-1 well in Iran and was subsequently appraised with Khasab-1, drilled byElf 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 commercialrates. The National Iranian Oil Company (NIOC) acquired 3D seismic over the field and approximately80 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 toproduce an agreement. Although such negotiations are continuing, the Block 8 partnership has sincedecided to pursue an Oman only development. Heritage advises that the Operator has secured agreementfrom the Sultan of Oman’s government to develop the field. However, public domain data from NIOC inIran suggests that an Iranian development is likely to proceed imminently. RPS is not in a position to opineon the legal status of the development.3.3.1. DatabaseThe West Bukha field is covered by 2D seismic acquired from 1974-1986, this data is poor quality. TheIranian National Oil Company acquired a 3D survey over the West Bukha field which covers the Omanand Iranian parts of the field. This survey is high frequency in the upper section but very good quality atthe reservoir depth. The West Bukha 3D has been depth migrated, this data was used prior to the drillingof the West Bukha-2 well where it was found that velocities had been inaccurately modelled. Well Datafrom four wells was made available, West Bukha-1, West Bukha-2, Henjam-1 and Khasab-1. Full log suiteswere made available for these wells as well as geological and test data. A static geological modelwas provided.3.3.2. Geology & GeophysicsThe field consists of a single contiguous NW-SE trending fault and dip closed structure covering an area ofapproximately 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 isconsiderable variation in thickness of the Ilam and Mishrif Formations linked to sedimentary depositionalong 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 theseformations thin to around 50 m. The Mauddud Formation has an average thickness of approximately 80 mthroughout the field and is separated from the underlying Sabsab and Thamama Formations by the NahrUmr shale with an average thickness of 136 m. The Sabsab and Thamama reaches a total thickness ofaround 400 m.The Operator and Heritage have interpreted three horizons across the West Bukha field; Top Ilam, TopNahr Umr and Top Thamama. The first two horizons define the structural envelope of theMishrif-Mauddud reservoir (Figure 9).(4) We note that this consequence has been previously ignored. However, the operator has stated (Sept.07 OCM Minute) that heexpects Bukha production to cease once West Bukha comes on stream.83

RPS EnergyHeritage Oil – Competent Persons ReportFigure 9:Top Mishrif Depth Map21FEB200823154113The 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. Theinterpretation ties all of the wells in the field except for the Khasab-1 well where the interpretation is some30 msec deeper than the well top. The TD relationship at Khasab-1 is calculated from uncalibrated soniclogs and therefore the formation tops in this well may not be accurate. RPS has reviewed the interpretationand 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 theinterpretation and mapping of these reflectors and considers them to be reasonable. The interpretationsensibly follows structural trends and the horizon ties the formation tops in the wells where the Thamamahas been penetrated.84

RPS EnergyHeritage Oil – Competent Persons ReportFigure 10: West Bukha 3D inline 112226FEB200822314633The 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 impacton velocities. Despite this approach West Bukha-2 penetrated the reservoir some 80 m shallower thanpredicted which invalidated this method. The current maps are based on an average velocities for eachhorizon derived from well data. There is little variation in average velocities across the field, although aneastward decrease in average velocity is not supported by well data and velocities at the extreme west andeast of the model exceed the velocities in the wells although not markedly. RPS considers the depthconversion reasonable.A facies model has been developed by the Operator which has been reviewed by RPS and appearsreasonable. The Mauddud shows little variation in thickness across the field and the subunits are the samein all wells drilled in the field. All nine sub units across the field are carbonate platform facies. Correlationwith the Bukha filed shows that Mauddud sub-units 7, 8 and 9 are missing in Bukha which indicates theposition of the shelf is between West Bukha and Bukha. Correlation with Bukha and Tibat shows aback-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 thefinal 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 andHenjam-1, whereas West Bukha-1 and Khasab-1 have only the deepest Mishrif-1 sub- unit. The Henjam-1and West Bukha-2 wells are interpreted to be on the carbonate platform during Mishrif deposition withWest Bukha-1 and Khasab-1 existing on the carbonate slope. Heritage has used an isopach thickness mapto determine the extent of the platform and the position of the slope. This is a reasonable approach asvariation in the thickness of the Mishrif is the predominant variable in the thickness of the Ilam-Nahr Umrisopach that was used to define the platform. This thickness variation is also visible on the seismic where asingle trough across the field at the Top Ilam becomes a trough-peak-trough to the north. Reservoir qualityand thickness are interpreted to improve to the north where the Mishrif is thickest. If this is the case, wellsdrilled to the SW of West Bukha-2 are unlikely to encounter the better carbonate platform facies and thereservoir will be similar to West Bukha-1.3.3.3. In Place VolumesRPS calculated in place volumes for the Mishrif/Mauddud and for the Thamama.85

RPS EnergyHeritage Oil – Competent Persons ReportAs discussed above the Mishrif-Mauddud reservoir thickness varies considerably over the field. Themajority of this variation occurs in the Mishrif Formation. The thicker isopachs represent the platformcarbonates drilled at Henjam-1 and West Bukha-2 as opposed to the slope facies drilled at West Bukha-1and Khasab-1. These platform carbonates are cleaner better reservoir facies and therefore their extent hasbeen modelled when calculating GRV. Isochron maps have been used to determine the extent of this betterreservoir facies in line with previous studies carried out by Indago and Novus. Gross rock volumes werecalculated from the Top Mishrif to Top Nahr Umr for the whole field. The GRV of the better Mishrifreservoir was calculated from the top Mishrif to top Mishrif 1 unit over the area interpreted to be part ofthe platform above the fluid contact. The Mishrif 2 and 3 units GRV was then removed from the total fieldGRV so that separate reservoir parameters could be applied to both GRVs. These two separate cases werethen consolidated. For the Top Mishrif reservoir, a surface was calculated by isopaching 23 m down fromthe Top Ilam depth surface to account for the average thickness of the Ilam and Laffan units across thefield (16-27 m in the wells). The Top Mishrif 1 surface was calculated by isopaching 75 m up from RPS’sTop Mishrif surface to account for the Mishrif 2 and 3 units present in Henjam-1 (61m) andWest 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 inall cases were set to 100 per cent. as the pervasive fractures in the reservoir probably connected the fullvolume of matrix porosity. Clay volumes within the reservoir sequences are not high and there are fewindividual shaley beds, both the Thamama and the Mishrif-Mauddud are clean limestones with a few thinshale beds.Porosity in these tight carbonate reservoirs is very low. Average values for both reservoirs is between 1 and3 per cent. The Mishrif-Mauddud porosity was determined from petrophysics carried out on West Bukha-1and West Bukha-2A. The Mishrif-Mauddud was separated into two zones for volumetric purposes; theMishrif1-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 theslope facies found at West Bukha-1. The Thamama porosity was determined from petrophysics carried outon West Bukha-1 and West Bukha-2A.Water saturation is the most poorly constrained reservoir parameters. Low porosities make thedetermination of S w difficult and S w varies markedly between the West Bukha-1 and -2 wells. A wide rangeof S w has been used in the probabilistic calculation. A normal distribution of S w was used for bothreservoirs with a p90 value of 49 per cent. in both reservoirs and a p10 value of 18 per cent. in the Mishrifand 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 evaluationis inconclusive and fluid contacts have been estimated from RFT data and production test results. Resultsfrom 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 theuncertainty. A minimum contact of 4,040 m TVDSS was taken from the deepest hydrocarbons tested inWest Bukha-2A, the most likely contact of 4,300 m TVDSS was based on RFT pressure data from wells inthe field and a maximum contact of 4,310 m TVDSS was based on the highest known water in thefield in the Khasab-1 test.For the Thamama a similar approach was used to model the uncertainty in water contact. Pressure data isinconclusive so a normal distribution based on a minimum contact of 4,163 m TVDSS, the lowest knownoil in West Bukha-2A, and a maximum contact of 4,268 m TVDSS from pressure data was used.86

RPS EnergyHeritage Oil – Competent Persons ReportA summary of input rock and fluid properties is given in Table 12.Low Mid HighMishrif/MauddudGRV ............................................. MM m 3 1,671 3,844 4,023N:G.............................................. % 1 1 1Porosity-Mish-Maudd ................................. % 1.3 1.7 2.1Porosity- Mish 2&3 ................................... % 1.7 2.85 4.0Sw............................................... % 50 33 18.51/FVF ............................................ stb/rb 0.392 0.370 0.351ThamamaGRV ............................................. MM m 3 559 1,091 1,622N:G.............................................. 1 1 1Porosity ........................................... % 1.6 2.3 3.0Sw............................................... % 50 40 301/FVF ............................................ stb/rb 0.488 0.455 0.426Table 12:West Bukha Volumetric Input ParametersIn-place volumes were calculated probabilistically for the Mishrif/Mauddud and Thamama reservoirs forboth 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 p10Mishrif/Mauddud ............................. 168.0 242.0 331.0 53.6 82.9 119.0Thamama ................................... 54.5 88.5 136 24.8 41.2 62.7Total ................................... 252.0 335.0 434.0 91.2 126.0 267.0N.B.The totals are the p90, p50 and p10 of the stochastically consolidated distributions.Table 13:West Bukha In place Volumes 100 per cent. Basis3.3.4. Petroleum Engineering3.3.4.1. Reservoir Fluid PropertiesThere has previously been debate amongst the legacy owners of the West Bukha field as to whether thereservoir contains a rich gas (or ‘‘condensate’’) type fluid, or a volatile oil, and latterly the field ownershave come to the conclusion that the reservoir fluid is a volatile oil. Such confusion is common when thefluid is a near-critical point fluid, as liquid:gas ratios during short well tests can be misleading, andrepresentative sampling difficult. We note that the NIOC has always maintained that the field is a volatileoil field.Upon examination of the fluid samples captured in wells Henjam-1 and West Bukha-2, and the laboratoryanalyses of same, we have concluded that the fluid is more likely to be oil at reservoir conditions, for thefollowing reasons:The methane (‘‘C 1 ’’) content is below 60mol per cent.;The test separator GOR 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 bepossible on a gaseous fluid).The initial reservoir fluid composition is as shown in Table 3.6 overleaf. The source of this is the PVTanalysis of samples from DST 2 in the Mishrif Formation in Well West Bukha-2; the reservoir fluid in theunderlying Thamama formation is similar. Approximately 1.4 mol per cent. H 2 S has been measured in thereservoir samples, and approximately 14 mol per cent. CO 2 and N 2 .87

RPS EnergyHeritage Oil – Competent Persons ReportThe initial reservoir pressure and temperature of the Mishrif Formation has been measured as 7,285 psiaand 295 F (values are commensurately higher in the deeper Thamama Formation).3.3.4.2. Well Testing & DeliverabilityThere have been numerous tests in the West Bukha/Henjam wells over the years, and these aresummarised in Table 14, below.Interval Oil Rate Gas Rate Choke WHFPWell 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 1,4672 June, 1987 3,846- Mauddud 543 2.3 48/64 1473 June, 1987 3,729- Mishrif 459 2.7 128/64 123West 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 TestsIt 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 issuch that little or no flow is possible without the presence of fractures (matrix permeability is typically lessthan 1 mD). The latest well (West Bukha-2) provides a modern suite of data, including downhole pressuredata from the DSTs, and we have analysed the Mishrif test (DST #2). The key results of our analysis areas follows:Permeability, k e ..................... 0.673 mDTotal skin, S ........................ 6.95Omega, ......................... 0.0389 (a measure of fracture storage)Lambda, ......................... 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 ofcommercial flow rates. No depletion was detected during the test, and the well’s PI was approximately6.4 stb/d/psi.Component Mole % Weight %H 2 Hydrogen ........................................... 0.10 0.00H 2 S Hydrogen Sulphide .................................... 1.42 0.95CO 2 Carbon Dioxide ...................................... 8.48 7.42N 2 Nitrogen ........................................... 5.47 3.01C 1 Methane ........................................... 53.70 16.95C 2 Ethane ............................................. 5.01 2.96C 3 Propane ............................................ 3.32 2.87iC 4 i-Butane ............................................ 1.04 1.19nC 4 n-Butane ........................................... 1.93 2.20C 5 Neo-Pentane ........................................ 0.02 0.03iC 5 I-Pentane ........................................... 1.05 1.48nC 5 n-Pentane .......................................... 1.09 1.54C 6 Hexanes ............................................ 1.56 2.64M-C-Pentane ........................................ 0.33 0.54Benzene ............................................ 0.28 0.43Cyclohexane ......................................... 0.48 0.80C 7 Heptanes ........................................... 1.10 2.1788

RPS EnergyHeritage Oil – Competent Persons ReportComponent Mole % Weight %M-C-Hexane ........................................ 0.52 1.01Toluene ............................................ 0.64 1.15C 8 Octanes ............................................ 1.18 2.64E-Benzene .......................................... 0.14 0.30M/P-Xylene ......................................... 0.48 1.00O-Xylene ........................................... 0.16 0.34C 9 Nonanes ........................................... 0.98 2.481,2,4-TMB .......................................... 0.19 0.45C 10 Decanes ............................................ 1.17 3.26C 11 Undecanes .......................................... 1.03 2.98C 12 Dodecanes .......................................... 0.86 2.73C 13 Tridecanes .......................................... 0.78 2.68C 14 Tetradecanes ........................................ 0.66 2.47C 15 Pentadecanes ........................................ 0.62 2.52C 16 Hexadecanes ........................................ 0.49 2.12C 17 Heptdecanes ........................................ 0.40 1.87C 18 Octadecanes ......................................... 0.36 1.78C 19 Nonadecanes ........................................ 0.34 1.76C 20 Eicosanes ........................................... 0.29 1.59C 21 Heneicosanes ........................................ 0.24 1.40C 22 Docosanes .......................................... 0.22 1.33C 23 Tricosanes .......................................... 0.19 1.19C 24 Tetracosanes ......................................... 0.17 1.11C 25 Pentacosanes ........................................ 0.15 1.01C 26 Hexacosanes ......................................... 0.14 0.96C 27 Heptacosanes ........................................ 0.12 0.92C 28 Octacosanes ......................................... 0.11 0.83C 29 Nonacosanes ........................................ 0.10 0.78C 30 Triacontanes ......................................... 0.10 0.79C 31 Hentriacontanes ...................................... 0.08 0.67C 32 Dotriacontanes ....................................... 0.08 0.71C 33 Tritriacontanes ....................................... 0.05 0.43C 34 Tetratriacontanes ..................................... 0.06 0.56C 35 Penatriacontanes ..................................... 0.05 0.51C 36 + Hexatriacontanes Plus .................................. 0.37 4.49Totals .......................................... 100.00 100.00Note: 0.00 means < 0.005Table 15:Initial Composition of West Bukha Wellstream3.3.4.3. Development Plan (Subsurface)The development plan on the Omani side of the field involves the deepening of West Bukha-2 and thedrilling 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. Duringthis phase, field performance will be monitored to determine the need for future wells (Phase IIand 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 withthe ability to selectively produce from one formation or both—there is no final decision yet on whichoption to run with.89

RPS EnergyHeritage Oil – Competent Persons Report3.3.4.4. 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 furtheractivity. However, NIOC representatives have placed in the public domain, comments and suggestionsconcerning 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 Henjamside 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-kmpipeline 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 thenear future; Gas would be transferred to Gheshm. The oil would be separated on Gheshm Island and then wouldbe 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 BukhaOperator 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 ofthe Omani side of the field (6)The sides will eventually agree on a unitisation or a production splitThis 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 datesbetween 2Q 2008 in the p10 case and 1Q 2009 in the p90 case.3.3.4.5. Recovery MechanismsThe dominant recovery mechanisms in the reservoir are likely to be solution gas drive, fracturecompaction, oil expansion and a degree of aquifer influx. Such reservoirs are not good candidates for wateror 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 therecovery from similar reservoirs under natural depletion in the region, with slightly better RFs. RPS isaware 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 ProfilesThe Operator commissioned a consultant to generate the profiles for its development plan using numericalreservoir simulation (7) . We have examined this work in detail and find that the p90 profile, in particular theinitial sustainable rate, is not supportable, as the location of the second well and the reservoir quality atthat location are as yet unknown, and the variation in same can be great. In addition, reservoir simulationnot corroborated by sustained production, and with limited data to constrain the model, is not whollyunique or dependable. To mitigate this risk, the Operator has studied fracturing and facies to optimise thelocation 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 futureproduction; however the validity of same is enhanced when there is sufficient production history to validate the model, andestimators must have an understanding of the limitations of simulation.90

RPS EnergyHeritage Oil – Competent Persons ReportEstimation of the Product StreamsIn addition to the above estimation of the ‘‘black’’ oil production, reserves estimates of C 3 , C 4 , dry gas, andcondensate are required for completeness.To achieve this, we have used an Equation of State (‘‘EoS’’) PVT simulator to perform an equilibrium flashon the expected wellstream composition above and below the bubble point. The following yields per stb ofblack oil were obtained from this exercise (Table 16):Above Bubble PointAverage Below Bubble PointThamamaDry gas ...................................... 1.461 ft 3 17.047 ft 3C3.......................................... 0.0574 stb 0.5529 stbC4.......................................... 0.0549 stb 0.4789 stbLPG total ..................................... 0.1122 stb 1.0319 stbCondensate ................................... 0.0867 stb 0.6530 stbMishrifDry gas ...................................... 1.922 ft 3 13.147 ft 3C3.......................................... 0.0650 stb 0.3959 stbC4.......................................... 0.0559 stb 0.3282 stbLPG total ..................................... 0.1209 stb 0.7241 stbCondensate ................................... 0.0841 stb 0.4319 stbTable 16:Estimated Product Yields from West Bukha WellstreamThese were used in combination with black oil production, reserves-weighted between the Mishrif andThamama 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 ofsustained, stable production to ratify the yields, which will also vary as a function of which formationsare open.Developmental RiskAt this pre-production stage, there are developmental risks, in addition to the obvious reservoir risks. Therisks, which may impact the timing and amount of future cash flow—all standard at this stage of adevelopment 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 alater agreement between the Iranians and Omanis.91

RPS EnergyHeritage Oil – Competent Persons ReportThe production profiles for the 1P, 2P and 3P cases are shown in Figure 11 to Figure 13.8,00016.0Oil, Propane, Butane & Condensate Annual Average Rate(stb/d)7,0006,0005,0004,0003,0002,0001,00025,000020092010201120122013201420152016201720182019202020212022202320242025202620272028202920302031203220332034203520362037Black Oil Propane Butane Condensate Sales GasFigure 11:1P Production Profile for West Bukha14.012.010.08.06.04.02.00.0Sales Gas Rate (MMscf/d)26FEB200822320154504520,0004035Liquid Rates (stb/d)15,00010,000302520Gas Rate (MMscf/d)5,000020082009201020112012201320142015NB "2008" is only the period 1/11/08 to 31/12/08201620172018201920202021202220232024202520262027202820292030203120322033203420352036Black Oil (stb/d) Propane (stb/d) Butane (stb/d) Condensate (stb/d) Sales Gas (MMscf/d)Figure 12:2P Production Profile for West Bukha15105027FEB20080426303692

RPS EnergyHeritage Oil – Competent Persons Report30,0004025,000353020,00025Liquid Rates (stb/d)15,00010,0005,000020082009201020112012201320142015NB "2008" is only the period 1/09/08 to 31/12/0820162017201820192020202120222023202420252026202720282029Black Oil (stb/d) Propane. C3H8 (stb/d) Butane, C4H10 (stb/d) Condensate (stb/d)Figure 13:3P Production Profile for West Bukha20302031203220332034Sales Gas (MMscf/d)20352036Economically recoverable reserves are discussed in the economics section, Section 7, below.20151050Gas Rate (MMscf/d)27FEB2008042631813.3.4.7. Facilities & CostsAs discussed above, RPS has assumed that West Bukha will come on stream in 1Q 2009 by means of awellhead tower tied back to Bukha central. West Bukha has several liquid streams. Condensate will be soldto existing long term customers, with LPG and Butane being sold to local markets. Modifications to Bukhaand the RAKGAS plant will be required but these are assumed not to be significant in comparison to theoverall development cost. Total costs for the platform, tie-back and modifications to RAKGAS areestimated to be US$96 MM including some contingency. Three new deep production wells are required inthe p50 case together with costs to deepen the West Bukha 2 appraisal well. RPS understands that theWest Bukha-3 well will be drilled during 2008 after installation of the wellhead tower at a cost estimated atUS$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 fieldOpex of US$2.5 MM plus the cost of operating the existing facilities which has been running at US$5 MMper annum. RPS has assumed periodical workover would be required and workover costs are included atUS$4 MM every three years. There is a General and Administrative (G&A) cost of US$1.5 MM perannum assumed during field life.Abandonment liability for the West Bukha facilities including the removal of the surface facilities andplugging and abandoning wells reverts to the government.4. ZAPADNO CHUMPASSKOYEThe Zapadno Chumpasskoye Licence is located in the West Siberian Basin in the Khanty-MansyiskProvince of Russia. Six producing oil fields operated by Lukoil surround Zapadno Chumpasskoye. Thenearest city is Langepass located 8 km to the east. Heritage acquired the field in November 2005 fromTNK-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 gathering202 km of new seismic, constructing a road, separation facility and drilling cluster to conduct furtherappraisal drilling and commence pilot operation. An existing well was re-entered and three new wells havebeen drilled.93

RPS EnergyHeritage Oil – Competent Persons Report4.1. Data AvailableData from the surrounding fields was sparse because competitor data is proprietary. A variety of data wasavailable for this review. Seismic data coverage (2006 survey and the older data) comprising 2D lines shotat 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 havebeen drilled in 2007 (P3 and P2) and a third (P4) was finishing drilling when this report was beingprepared. 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 226and P3 were provided.4.2. Geology4.2.1. Regional SettingThe Upper Jurassic sequence in the Zapadno Chumpasskoye Licence is understood to comprise asequence of shallow marine clastics, which are widely deposited in the West Siberian Basin. The UpperJurassic is some 60 to 70 meters thick and includes a lower section of claystones and upper sand sequenceinterbedded with siltstones and claystones. The Upper Jurassic in the area is overlain by the BazhenovFormation, a 20 to 25 metre thick bituminous shale which is both the source and the cap rock forthe reservoir.The six fields surrounding Zapadno Chumpasskoye are also reported to be producing from theUpper Jurassic.4.2.2. Zapadno Chumpasskoye FieldThe data from Russian drilled wells available for evaluating net sand, net pay and fluid contact is limited toSP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. These are lowresolution tools and the resistivity logs are unfocused. There are no porosity logs. The SP logs werenormalised to enable a consistent comparison of sand quality between wells. Net sand was initially pickedat a typical VCL cut-off 50 per cent. However, to compensate for the low resolution of the SP and thepresence of thin beds, a higher VCL cut-off was accepted for the thinner layers (i.e. thickness less than5m). The Russian lateral logs were reviewed for evidence of hydrocarbons in the wells and to determinethe fluid contacts. The log response is asymmetrical and only a qualitative interpretation was possible. Theshallower hydrocarbon bearing sands were found to indicate resistivities approaching and exceeding40 Ohmm, whereas the deeper formation closer to the hydrocarbon-water contact tended towards15 Ohmm. The resistivity measurements in some of the thinner sands were uncertain due to poorlog 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 clasticsequence based on lithostratigraphy (no biostratigraphic data is available). Two sandstone intervals (theUpper and Lower J 1 Sandstones) were identified in the upper part of the sequence and correlated betweenmost of the wells using the SP logs. These occur below the base of the ‘low conductivity zone’, equating tothe Bazhenov shale which is the seal and source rock for the Jurassic reservoirs. The correlation has beenrevised based on data from the 2007 wells and additional older well data that has become availableto Heritage.The revised interpretation suggests that the Upper J 1 Sand is very localised and no volumes are nowassigned to this sand. Well spacing is large in this licence (between 2 and 7 km) and lateral variations insand 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 thelogs 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 atreservoir level is insufficient to define the reservoir thickness. Effectively the only presently perceived usefor these data is to define the structure at the top of the reservoir sequence which is seen to be a simplenorth-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 the94

RPS EnergyHeritage Oil – Competent Persons Reportmaps, but it is expected that faults will cut the sequence and offset the relatively thin (generally less than10m) sands. Due to the stratigraphic nature of the trap, seismic interpretation is not regarded as critical tothe volumetric evaluation.Heritage’s Net Oil Pay thickness maps were reviewed and modified as appropriate including an estimate ofthe pinch out edge to the south (the exact position of this pinch out cannot be precisely located on theseismic). 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 (possibleODT in Well 100). The Net Oil Pay thicknesses above each of these contacts were hand contoured,digitised and Net Pay Rock Volumes calculated. The p50 Net Pay Map is shown in Figure 14.Figure 14:Lower J 1 Sand—RPS Net Pay Map (p50 Case)21FEB2008231553204.2.3. PetrophysicsRPS undertook an independent petrophysical review of wells P2ST and P3. The S w values interpreted fromwestern logs in Well P3 were higher than expected. As a result a detailed review of core and water analysisdata derived from core taken from Well P3 was undertaken. These data provided a basis for calibrating thelogs from P2 ST and P3. Core was taken from Well P3 where a water base mud was tagged with afluorescent dye. The core barrel contained a glass fibre inner barrel that was filled with depolarizedmineral oil. To obtain the background reading of fluorescent dye concentration, the tagged mud wassampled regularly during coring. However, no fluorescence was detected from the water extracted from the95

RPS EnergyHeritage Oil – Competent Persons Reportcore and it is therefore considered that the core did not suffer filtrate invasion in the volumes sampled forwater extraction, and no invasion corrections were applied.Values of R w were taken from the data supplied by Heritage where residual water was extracted from thecore and its resistivity determined. The average value from 8 samples reported was 0.277 Ohmm at 20 Cwith standard deviation of the mean of 0.012 Ohmm. Arps’ equation (8) was used to convert this to reservoirtemperatures. 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 were1.77 and 1.85, respectively. A produced water analysis was supplied by Heritage which was obtained bycentrifuging an oil sample from co-mingled production from Wells S226 and P3. The chemical analysisobtained a salinity of 49,454 ppm, which has an estimated R w of 0.143 Ohmm at 20 C.Because of the ambiguity in the results from the brine analyses, the 0.277 Ohmm R w at 20 C was used tocalculate saturations at the p90 level, and the 0.143 Ohmm R w at 20 was used to calculate saturations atthe p50 level.In the case of well P2ST, VSH was derived from the lower value from the density neutron cross plotmethod and a linear Gamma Ray VSH method derived from the Potassium and Thorium component ofthe gamma ray count. Parameters are presented in Table 1 in the Appendix. For well P3, shale volume wasdetermined 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 inLCc was derived from the density log. The parameters used in calculating porosity for both wells arepresented in Tables 1 & 2 in the Appendix.For both wells, total water saturation was calculated using the Archie equation (9) . Effective watersaturation 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 notbeing resolved fully by tool responses, and that the results of the interpretations have been influenced bysmoothed tool responses. A p50 case for water saturation has used an R w of 0.143 Ohm at 20 C. An R w of0.277 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 Transactionsof the AIME 146 (1942).(10) A. Poupon, J, Leveaux ‘‘Evaluation of Water Saturation in Shaly Formations’’. SPWLA 12 th Annual Logging Symposium,May 2-5 1971.96

RPS EnergyHeritage Oil – Competent Persons Report21FEB200823151631Figure 15:CPI for Well P3 over Reservoir Interval for p50 Saturation Case4.3. In Place VolumesPorosity, saturation and formation volume factor ranges were estimated based on the RPS review ofpetrophysical 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 thesurrounding area. As a result of the differences in interpreted S w a broad range of S w was used in thevolumetric calculations. Input parameters are shown in Table 17.Low Mid HighNet Pay Rock Volume (MM m 3 )...................................... 131 455 854Porosity (%) .................................................... 15 17 19Oil Saturation (%) ................................................ 45 060 65B oi (rb/stb) ...................................................... 1.2 1.25 1.30Table 17:Lower J 1 Sand Input ParametersSTOIIP has been estimated probabilistically and is summarised Table 18 below.STOIIP (MMstb)p90 p50 p1090.3 233 419Table 18:Zapadno Chumpasskoye, Lower J 1 Sand, STOIIP Estimates (MMstb)97

RPS EnergyHeritage Oil – Competent Persons Report4.4. Petroleum Engineering4.4.1. Reservoir Fluid PropertiesThe Lower J 1 Sand contains an undersaturated oil at an initial pressure and temperature of approximately28 MPa (4,018 psia) and 83 C (181 F), respectively, at a depth of 2,750 m. The produced oil has a densityof 834 kg m -3 (~38 API). The in-situ viscosity of the oil is likely to be 2-3 times that of water, and thebubble point of the reservoir oil is 1,320 psia (the implication of these factors is discussed below). Theinitial solution GOR (R si ) is 410 scf/stb, and the initial formation volume factor (B oi ) is 1.25 rb/stb.4.4.2. Well Performance & DeliverabilityTwo wells have been tested and produced on the acreage, namely 226 and P3. Their production history isshown in Figure 16 and Figure 17 below. The highest rate achieved by each well is 476.5 stb/d and288.9 stb/d, respectively.Figure 16:Well 226 Production History27FEB20080426380698

RPS EnergyHeritage Oil – Competent Persons ReportFigure 17:Well P3 Production History27FEB200804271079Whist decline has clearly set in, it is very early in the producing life of the well and the field, and anydecline will change when water injection commences and downhole pumps are installed. The declinesobserved 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 thetubing 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 beencountered are 300 to 600 stb/d.As one of the measures to improve drilling performance and improve well performance by minimizing wellimpairment, Heritage intends to replace the current rig and contractor in order to improve drillingprocedures and avoid damaging the future wells—the new rig and contractor will arrive some time afterthe 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 reservoirstudies and early wells to establish the efficacy of a full field development (‘‘FFD’’) using an inverted5-spot pattern. The initial approval covers the drilling of up to 53 wells including 13 injection wells. Thatapproval permits ongoing development and production activities during which it is expected that in 2010the Company will present an evaluation of the results obtained and present its plan for furtherdevelopment. Whilst the FFD has not yet been approved we believe it is reasonably certain that suchapproval will be forthcoming.The long-term development plan is to drill a number of inverted 5-spot patterns, consisting of injectorsinside a ‘‘square’’ with a producer ion each corner of this square. Figure 18 illustrates how several of thesepatterns might look (source: Heritage).99

RPS EnergyHeritage Oil – Competent Persons ReportFigure 18:27FEB200804274190Illustration of Inverted Five-spot Patterns at Zapadno ChumpasskoyeThe well count will be built up over the next few years, The current plan to maintain reservoir pressure isto inject water injection at high voidage replacement ratios (‘‘VRR’’s) (in excess of 1) to re-pressure thereservoir. Wells will be drilled from well pads, with maximum step-out from the surface location of 1.5 km.4.4.4. Recovery MechanismsWhist 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 waterinjection 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 createviscous fingers through the oil leg. Consideration is being given to the optimum reservoir pressurefor flooding.100

RPS EnergyHeritage Oil – Competent Persons Report4.4.5. Production ProfilesThe Company has performed sector and a ‘‘P90’’ low case full field simulation studies, and the key outputfrom the latter is shown pictorially in Figure 19 to Figure 21.Figure 19:Oil Rate & Cumulative from Full Field Simulation22FEB200803400027Figure 20:22FEB200803401971Water Injection Rate & Cumulative from Full Field Simulation101

RPS EnergyHeritage Oil – Competent Persons ReportFigure 21:Average Reservoir Pressure from Full Field Simulation22FEB200803404094Heritage has used a ‘‘downside’’ geological scenario in the simulator, as is necessary for the developmentplan submitted to the authorities. The above output shows oil rate building up to some 1,200 m 3 /d(7,548 stb/d) following water injection which builds to a peak rate of 2,800 m 3 /d (17,611 bbl/d). This rateeventually far exceeds voidage and the reservoir is re-pressurised (Figure 21), although in practice it is notnecessary 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 2015p90New Producers ....................... 2 4 8 16 16 2Cumulative Producers .................. 3 7 15 31 47 49New Injectors ........................ 4 8 8 12Cumulative Injectors ................... 0 0 4 12 20 32Total in Year ..................... 2 4 12 24 24 14p50New Producers ....................... 2 4 8 16 14 14 13 10 2Cumulative Producers .................. 3 7 15 31 45 59 72 82 84New Injectors ........................ 4 8 8 8 9 8 1Cumulative Injectors ................... 0 0 0 8 16 24 33 41 46Total in Year ..................... 0 4 12 24 22 22 22 18 3Table 19:The p90 and p50 Drilling Schedule for Zapadno ChumpasskoyeThe simulation work is reasonable, but of course is not matched to a sustained period of history (and isthus 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 simulatorsurpass those rates seen in the field to date, albeit in just two wells. We have used the above drillingschedule, the rate build-up from the simulator, but reduced rates to construct a production profile for our1P case; we have also allowed for downtime that is likely to occur to well, pump, facility, and pipelineavailability.102

RPS EnergyHeritage Oil – Competent Persons ReportOur p50 case is scaled to honour potentially higher initial well rates and an improved recovery factor, andalso the p50 scenario drilling schedule (a total of 84 producers and 46 injectors). The Company has not yetcreated a p10 scenario. To do this, we have used the area of the field inside the 1 m net pay contour todetermine the well count, an assumption of improved well rates (600 stb/d) and recovery factor. Theresulting profiles are shown in Figure 22 to Figure 24 (note: in all these figures, the 2007 rate is the averagefor the period 1 October to 31 December, 2007).7,0006,0005,000Gross Oil Rate (stb/d)4,0003,0002,0001,000027FEB2008043328822007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028Figure 22: 1P Production Profile for Zapadno Chumpasskoye18,00016,00014,000Gross Oil Rate (stb/d)12,00010,0008,0006,0004,0002,000020072008200920102011Figure 23:201220132014201520162017201820192020202120222023202420252026202720282P Production Profile for Zapadno Chumpasskoye27FEB2008043330812029203020312032103

RPS EnergyHeritage Oil – Competent Persons Report50,00045,00040,00035,000Gross Oil Rate (stb/d)30,00025,00020,00015,00010,0005,000027FEB2008043332262007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032Figure 24: 3P Production Profile for Zapadno ChumpasskoyeThe summary output from the three RPS cases, combined with the STOIIP estimates from 4.3, above isgiven in Table 20:1P 2P 3PSTOIIP (MMstb) .............................................. 90.3 233.0 419.0URR (11) (MMstb) .............................................. 24.9 64.4 172.8URR/well (MMstb) ............................................ 0.509 0.767 0.971Table 20: Summary of Results for Zapadno Chumpasskoye (12)This range of outcomes is reasonable for the range of reservoir quality expected to be encountered inthe block.Developmental RiskWe have categorised these volumes as reserves despite the absence of formal approval of the FFD as thereis a reasonable expectation that all required internal and external approvals will be forthcoming, and thereis evidence of firm intention to proceed with development within a reasonable time frame (as requiredunder 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 adevelopment and by no means specific to for Zapadno Chumpasskoye—include but may not be limited tothe following: The timing and any conditions of the formal approval by the Russian authorities of the developmentplan efficient functioning of the facilities; The timing and operation of a replacement drilling rig; we note that Heritage is in receipt of acommercial 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 analysisterminates 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 remainderflared. We are not aware of any limitations to the volume of gas that can be flared.104

RPS EnergyHeritage Oil – Competent Persons ReportThe installation and commissioning of new facilities of appropriate size for the production, processingand transportation of the produced oil; (Heritage advise that CND’s plan is currently in front ofregulators for their approval)The raising of sufficient capital funds to cover these development costs.4.5. Facilities and CostsCommercial production commenced in 2007 on a small scale from two wells. The current plan is to drill upto 84 producers in the p50 case along with 46 Water Injection wells for reservoir support. Two drilling rigswill eventually be required with a planned 16 wells in years 2010 to 2012. The p50 Case is expected toproduce over 60 MMstb peaking at about 16,000 bopd in 2014. Capital expenditure (facilities costs) for themost likely case is estimated at US$180 MM including a 20 per cent. contingency. The 130 wells will bedrilled at a cost of average US$2 MM each. In the p10 case, with over 200 wells. RPS has assumed anadditional drilling rig is required from 2011. Production would be over 170 MMstb with a capitalexpenditure of over US$300 MM. Operating costs are assumed to be US$12 MM per annum during theplateau years plus a further US$1.5 MM per annum for G&A.5. UGANDA—BLOCKS 1 & 3A5.1. OverviewUgandan Block 3A is located in the south of Lake Albert and covers the southern part of the Ugandan sideof Lake Albert. Block 1 is located on land to the north of Lake Albert. Lake Albert is a largest lake in thenorthern sector of the Western Rift. The lake surface is approximately 618 m above sea level and its riftedmargins are more than 2,200 m above sea level in the west and more than 1,300 m in the east. Here, thegraben has an average width of 45 km and is approximately 190 km long. Whilst many of the Western Riftsegments contain deepwater lakes, such as Lake Malawi (750 m) and Lake Tanganyika (1,500 m), LakeAlbert has relatively shallow water depths (approximate maximum of 60 m) but is believed to have similarsediment thicknesses as the other lakes.The Albert Basin is the most petroleum prospective area in Uganda and is a classical active rift basin of theEast African Rift system.5.2. Data AvailableThe seismic database in Block 3A comprises 16 widely spaced 2D seismic lines of varying vintages2003-2005. The data quality in the northern half of the block is fair with well defined reflections down tothe base of the Tertiary basin fill. To the south of the block the regional data becomes increasingly poor andmapping of the deeper levels is particularly difficult. A 3D survey also exists over the Kingfisher discoverycovering 450 sq km along the south eastern lake shore, data quality is reasonable. Shallow data atKingfisher 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 availablefor 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 isgenerally very good with retention of amplitudes, coherent reflector packages and fairly crisp faultterminations. As noted above, seismic acquisition in Blocks 1 and 3A is not due for completion untilMarch 2008. Much of the area outside the 3D seismic in Block 3A will be covered by additional infill 2Dlines 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 numberof reported discoveries but RPS has no access to data from these wells.105

RPS EnergyHeritage Oil – Competent Persons Report5.3. Geological SettingThe 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 alongits length into individual, asymmetric basins, many of which contain lakes. Lake Albert is in the northernsector which trends from NNE to SSE. The rift is bordered on both sides by steeply dipping normal faultsystems 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, LakeGeorge and Lake Edward basins, changing progressively in trend from NNE to SSW to N-S, towards thesouth. The major tectonic stresses in the Albert Basin are extensional although there is evidence ofcompression. Inversion and compressional anticlines interpreted from public domain seismic data revealthese compressional episodes and probably represent localised inversion taking place within the riftingprocess due to oblique extension.The western border fault is a more steeply dipping normal fault than the eastern border fault with steeperuplifted flanks. Magnetic and gravity data suggest there are two main sub-basins separated by a basementhigh, which is a possible accommodation zone/transfer zone that formed along the NE-SW trendingeastern border faults.In general, the stratigraphic sequence in the Albert Basin is divided into two mega sequences, Pre-rift andSyn-rift. The pre-rift sequence is predominantly composed of Pre-Cambrian basement rocks that areexposed on the rift flank and shoulder of the Albert Basin. It predominantly consists of meta-sediments tohigh-grade metamorphic rocks, mainly comprising gneisses, granitic gneisses and quartzites. The sequenceis unconformably overlain by Early Tertiary sediments in many parts of the graben. However, there is also astrong possibility that the Tertiary sediments overlay Mesozoic sediments. The syn-rift sequence containsthick fluvio-lacustrine and lacustrine sediments of Cenozoic age, possibly ranging from Palaeogene?/EarlyMiocene to Recent.Oil is believed to be sourced from organic shales deposited in a lacustrine environment, where organic richshales are concentrated. Oil seeps occur along the Ugandan shore of Lake Albert. More than 15 confirmedoil 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 wallof major fault systems. The oldest syn-rift sedimentary units are coarse grained fluvial-deltaic sands. Thecoarse-grained basal syn-rift sequence passes upwards and laterally into a shale dominated sequencemarking the deep lacustrine phase, which can provide important seals and source rocks. Large riftbounding faults control the location and bathymetry of most rift lakes. Once extension stops there is nomechanism for preserving the water depth and sediments begin to fill the basin to base level. In acontinental rift this fill tends to be coarse grained fluvio-deltaic deposits that prograde over lacustrinesediments.The basin fill within the Albert Basin consists of Miocene to Pliocene age sediments capped by anapproximate 200 m thick layer of Pleistocene alluvium. The predominant facies within the graben islacustrine and marginal lacustrine siliciclastics and thick sequences of stacked fluvial channels. Fluviodeltaicsandstones may be thick and have good porosity. Interbedded shales, particularly where theycorrespond with lake high-stands are likely to be relatively thick and continuous, thus forming goodregional seals. Good seismic reflection continuity within these packages attest to the good seal potential forthese units. Tullow has been exploring a fault terrace north of Heritage’s Block 3A and has a number ofreported discoveries.Block 1 lies to the north of Lake Albert and from gravity maps appears to contain two sub-basins. Thenorthern sub-basin trends in almost N-S and is separated from the NNE-SSW trending southern sub-basinby basement structural highs. The Pakwach Basin is a small half graben, which has a NNE-SSW orientationand is separated from main Albert Basin by a basement high. The basin is probably filled by fluviolacustrineand lacustrine sediments of Palaeogene?/Early Miocene to Pliocene age and alluvial plainRecent sediments.Two live seeps on the Victoria Nile near Paraa have been confirmed by oil freely bubbling onto the surfaceof 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 otherseep has been identified in the area, the presence of the seep could simply be due to the fact that basins106

RPS EnergyHeritage Oil – Competent Persons Reportmay not seal perfectly. The presence of seeps in Block 3 and in Block 2, close to existing discoveries, alsosupport this hypothesis. The sub-basins and basement structural highs are prospective. There is, however, arisk that traps will be under-filled because of a possibly restricted source kitchen area in the Pakwachsub-basin. However, the prospects mapped in the southern part of this block should receive their oil fromthe Albert Basin via a good migration route.5.4. Geology & Geophysics5.4.1. Kingfisher 1The 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, Kingfisher1A, both flowed hydrocarbons to surface from thin Late Miocene—Pliocene sands. Kingfisher-1 tested alocally 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 PlioceneP1/M6 cycle.Figure 25:Seismic Section through Kingfisher 1 Well22FEB200803421223The Early Pliocene P2a sand tested in Kingfisher-1 is 12m thick. Kingfisher-1A penetrated three oilbearing sands within a 100m interval spanning the Miocene-Pliocene boundary at between 1,520 and1,630 m TVDSS (Figure 26). These sands vary in thickness from 10 to 30 m. No water contacts were seenin any sands(13) Heritage stratigraphic nomenclature107

RPS EnergyHeritage Oil – Competent Persons ReportFigure 26:Reservoir Section in Kingfisher 1A22FEB200803423317Source: HeritageThe Kingfisher structure is a 3-way dip closure against the southern basin-bounding fault (Figure 27). Themaximum areal closure is approximately 45 sq km. A deeper, probably Miocene basal sand, was theprimary target of the well but the vertical well and first sidetrack encountered basement before reachingthe primary target. A second sidetrack, which kicked off below the tested zones, was abandoned due tomechanical problems before reaching the Early Miocene target.Figure 27:RPS Cycle P1/M6 Depth Map, Block 3A22FEB200803425435108

RPS EnergyHeritage Oil – Competent Persons Report5.4.2. MappingHeritage 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 qualitydrops around the faults in Kingfisher but deeper units show the general trend of the data. RPS hasreinterpreted the area and modified the fault interpretation in the area of Kingfisher Northand Pelican Kingfisher basal sand—Interpretation of this unit is fairly robust over the Kingfisher 3D. Again, RPShas 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 faultsexist than those interpreted by Heritage G: Near Top Zone 2—Seismic quality around the leads is very poor, consequently fault and horizoninterpretation is open to question. Structures formed are caused by slight inflections in theinterpretation around faults that may be seismic artefacts.5.4.3. ProspectivityIn 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; PelicanMain, Pelican North and Pelican Shallow. The eastern area of the Pelican prospect is in a complexstructural zone where the basin bounding fault is met by a parallel intra-basinal fault. The Pelican Northand Shallow prospects are separated by significant vertical offset from the main Pelican prospect. A furtherprospect, Pelican West, is also a three-way dip structure but bounds the intra-basinal fault that convergeswith the main basin-bounding fault at Pelican. Heritage has identified a further three leads from 2Dseismic 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-thicknessapproach has been used to calculate GRV. RPS has re-gridded their modified TWT horizons and createddepth maps using a simple depth conversion using average velocities calculated from the time-depthrelationship seen at Kingfisher-1.Block 1 lies at the Northern end of the Albert Basin where the Nile exits Lake Albert. There is no wellcontrol in the block. The block lies updip of the Lake Albert source kitchen, and is at the focal point ofpotential hydrocarbon migration from the basin depocentre. Heritage has identified four very shallow (lessthan 600 m) and potentially very large prospects in the area of existing seismic coverage in Block 1. Theseare named Buffalo, Crocodile, Giraffe and Hartebeest (Figure 28).109

RPS EnergyHeritage Oil – Competent Persons ReportFigure 28: RPS Top Reservoir Depth Map, Block 122FEB200803432250The maximum size of the structures in Block 1 range from 5 to 69 sq km. Heritage mapping is based on astrong reflector which they interpret, based on seismic facies, to be the top of a sandy sequence. Theinterpretation of this unit is very robust as the seismic quality is very good. Heritage has identifiedamplitude anomalies at the crest of structures throughout the block which could be indicative ofhydrocarbon fill although the anomalies do not cover the entire area of the larger prospects. The concernthat any oil might be biodegraded due to the very shallow reservoir depth is partly allayed by the presenceof 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 forvolumes. RPS has re-gridded the mapped horizons and depth converted them using average velocitiescalculated 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 isunderstood to show the presence of some potentially interesting structures.5.5. VolumetricsRPS has used area-depth curves calculated from the RPS depth maps which were produced by RPS foreach prospect at each reservoir horizon. RPS applied an uncertainty on possible leak point/spill points tothe prospects. For the P1/M6 cycle an appropriate range of gross reservoir thickness was taken from theKingfisher 1A well and a stacking factor of three was applied to calculate the volume in the Kingfisherdiscovery and the Kingfisher North prospect. For other P1/M6 prospects a range of stacking factorsbetween 2 and 4 was applied as there is uncertainty over continuity of the reservoir sands. The basal sandsare interpreted to be thicker alluvial to fluvial early syn-rift sediments. Consequently, RPS has assumed agreater range of thicknesses than the younger Pliocene sands.RPS undertook an independent petrophysical evaluation of the Kingfisher well. The results of thisevaluation have been used to constrain the range of N:G, porosity and S w values used in the Plioceneprospects along the basin margin. Lower average porosities were assumed in the deeper Pliocene leads andthe Miocene basal sands.110

RPS EnergyHeritage Oil – Competent Persons ReportWater 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 theintercalated shale section suppressing the resistivity curves. An S w range of 20-50 per cent. has been usedfor 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 thenorthern 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 hasbeen used to support thickness estimates. Relatively higher porosity values have been used to account forthe shallow burial depth.A summary of input values for the volumetrics is given in Table 21.N:G (%) Porosity (%) S w B oi (rb/stb)p90 p50 p10 p90 p50 p10 p90 p50 p10 p90 p50 p10DiscoveryKingfisher Main P2a ............ 69 80 90 24 25 26 50 40 20 1.11 1.13 1.15Kingfisher Main P1/M6 .......... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17ProspectsKingfisher Main Basal sand ........ 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18Kingfisher North Cycle P1/M6 ...... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17Kingfisher North Basal sand ....... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18Pelican Light blue .............. 40 60 80 20 25 30 60 40 20 1.00 1.08 1.16Pelican Light green ............. 40 60 80 20 25 30 60 40 20 1.00 1.08 1.15Pelican Main Cycle P1/M6 ........ 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17Pelican Main Basal sand .......... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18Pelican North Cycle P1/M6 ........ 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17Pelican North Basal sand ......... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18Pelican Shallow Cycle P1/M6 ....... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17Pelican Shallow Basal sand ........ 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18Pelican West Cycle P1/M6 ......... 50 70 90 18 21 24 50 40 20 1.15 1.16 1.17Pelican West Basal sand .......... 50 70 90 16 20 24 50 40 20 1.16 1.17 1.18Lead A Cycle P1/M6 ............ 40 60 80 15 20 25 50 40 20 1.15 1.16 1.17Lead A Basal sand ............. 50 70 90 12 17 22 50 40 20 1.16 1.17 1.18Lead B Cycle P1/M6 ............ 40 60 80 15 20 25 50 40 20 1.15 1.16 1.17Lead B Basal sand .............. 50 70 90 12 17 22 50 40 20 1.16 1.17 1.18Lead C Cycle P1/M6 ............ 40 60 80 15 20 25 50 40 20 1.15 1.16 1.17Lead C Basal sand .............. 50 70 90 12 17 22 50 40 20 1.16 1.17 1.18Buffalo ..................... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10Crocodile .................... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10Giraffe ...................... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10Hartebeest ................... 40 60 80 25 29 32 50 40 25 1.01 1.06 1.10Table 21: Uganda Volumetric Input ParametersThe 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 andp10 in-place volumes, respectively.Contingent ResourcesIn Place Volume (MMstb)(MMstb)Low Best High(p90) (p50) (p10) Mean 1C 2C 3CP2a.................................. 9.4 13.4 18.5 13.7 1.9 4.0 7.4P1/M6 Cycle ........................... 74.5 382.0 1223.0 541.0 14.9 114.6 489.2Total ............................ 86.2 393.0 1234.0 554.7 17.2 117.9 493.6N.B. The totals are the p90, p50 and p10 of the stochastically consolidated distributionsTable 22:Kingfisher Discovery—STOIIP and Contingent Resource Estimate (100 per cent. Basis)111

RPS EnergyHeritage Oil – Competent Persons ReportThe wide range between the p90 and p10 STOIIP reflects the inherent uncertainty in the continuity of thetested sands and in particular the shallowest sand in Kingfisher 1A, which RPS interprets to be a channelsand.The estimated in place and recoverable Prospective Resources in Uganda Blocks 1 and 3A are given inTable 23. Recovery factors of 20, 30 and 40 per cent. have been applied deterministically to the p90, 050and p10 in-place volumes, respectively.STOIIPProspective Resources(MMstb)(MMstb)Low Best High Low Best High GPoS(p90) (p50) (p10) Mean (p90) (p50) (p10) Mean (%)Block 3AKingfisher main (Basal Sand) .......... 275 704 1,746 890 55 211 698 267 35Kingfisher north (P1/M6) ............. 22 105 243 123 4 32 97 37 43Kingfisher north (Basal sand) .......... 69 188 478 240 14 56 191 72 29Pelican main (P1/M6) ............... 59 195 529 257 12 59 212 77 38Pelican main (Basal sand) ............ 178 422 968 517 36 127 387 155 29Pelican north (P1/M6) ............... 1 7 22 9 0 2 9 3 18Pelican north (Basal sand) ............ 7 15 33 18 1 5 13 5 23Pelican shallow (P1/M6) .............. 21 51 118 63 4 15 47 19 18Pelican shallow (Basal sand) ........... 30 69 154 82 6 21 62 25 24Pelican west (P1/M6) ................ 11 38 102 49 2 11 41 15 23Pelican west (Basal sand) ............. 63 146 323 174 13 44 129 52 23Pelican (light blue) ................. 48 176 574 261 10 53 230 78 18Pelican (light green) ................ 48 176 574 261 10 53 230 78 18Lead A (P1/M6) ................... 23 231 1,399 511 5 69 560 153 13Lead A (Basal sand) ................ 111 368 1,224 562 22 110 490 169 9Lead B (P1/M6) ................... 68 277 829 381 14 83 332 114 13Lead B (Basal sand) ................ 32 102 333 154 6 31 133 46 9Lead C (P1/M6) ................... 339 1,241 3,345 1,620 68 372 1,338 486 12Lead C (Basal sand) ................ 139 589 2,531 1,101 28 177 1,012 330 9Block 1Buffalo .......................... 444 1,375 3,305 1,678 111 344 826 420 20Crocodile ........................ 65 124 228 138 16 31 57 35 20Giraffe .......................... 139 305 643 356 35 76 161 89 20Hartebeest ....................... 32 97 255 124 8 24 64 31 20Total 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 ofstatistical addition will, as a result of the central limit theorem, produce a P90 that is greater than the arithmetic sum of allP90 quantities and a P10 that is less than the arithmetic sum of all P10 quantities. The arithmetic sum of the mean quantitieshowever 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 EnergyHeritage Oil – Competent Persons ReportGiven the range of resources in the Albert Basin, the gross risked recoverable Contingent and Prospectiveresources have been consolidated stochastically and the p90, p50, p10 and mean is quoted in Table 24and presented graphically in Figure 29.Gross Risked Recoverable Resources (MMstb)p90 p50 p10 Mean280 793 1,731 923Table 24:Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPSTotal Risked Recoverable Resources120%100%Cumulative exceedance probability80%60%40%20%Figure 29:0%0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000Gross risked recoverable resources22FEB200803434111Consolidation of Gross Risked Recoverable Resources in Blocks 1 and 3A Reviewed by RPS (MMstb)5.6. Other ProspectivityIn an effort to obtain a full valuation of the potential prospectivity of all of their acreage in Uganda and toplan future exploration strategies, Heritage made estimates of the potential that the under-explored areasmay offer. This was beyond the scope of the RPS evaluation. Heritage recognises conceptual leads in areasbeyond seismic control. These conceptual leads are based on Heritage’s extensive regional and structuralknowledge 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 tobe present in the southern part of Block 1. This area has since been covered by seismic data which resultedin the identification of the Buffalo prospect in the location of conceptual structure E, as well as threeadditional prospects being mapped using the new seismic data in that vicinity. Heritage’s estimated meanSTOIIP 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 excessof 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 locatedin the northern part of Block 1 and one in the south-western extremity of Block 3A. The prospectiveresources calculated by Heritage for these three structures are in Table 25:113

RPS EnergyHeritage Oil – Competent Persons ReportThese evaluations are reported herein for completeness, but RPS does not warrant these estimates.Mean Unrisked STOIIP(100% basis) (MMstb)Block 3AConceptual Structure D .......................................... 464Block 1Conceptual Structure F .......................................... 2,925Conceptual Structure G .......................................... 2,925Total of Mean ............................................ 6,314Table 25:Heritage Conceptual Leads Mean Un-Risked STOIP (100 per cent. Basis) Not Reviewed by RPS)5.7. Petroleum Engineering5.7.1. Production Profiles for Kingfisher and Other Block 3A ProspectsThe Kingfisher well was tested in both the -1 and -1A well-bores; the former well-bore tested an isolatedsand, so RPS have concentrated on the latter tests, which are summarised below, including results of theRPS independent well test analyses.Interval Max Oil Rate Gas Rate Choke WHFPPTAWell DST (m MD) (stb/d) (MMscf/d) (‘‘) (psig) K (mD) S AP1KF-1 ...... 1 2,344-2,339 2,965 64/64 238 206 2.4 27-322,361-2,367(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 TestsAs can be seen, the reservoir quality is excellent, although there is a significant contrast between separatesands. The produced fluids from all these tests are similar, and fluid properties are summarised below. TheGOR is low and the fluid is highly under-saturated, so a solution gas drive will not develop.Depth p r T r p b B oi R si oDST Well (m MD) (psia) ( o F) (psia) (rb/stb) (scf/stb) g/cm 3 cp o APIDST2 ............. KF-1 1,785.0 2,566 171 1,035 1.11 161 0.808 6.0 31.1DST1 ............. KF-1A 2,355.5 316 187 1,285 1.17 263 0.790 4.0 31.1DST2 ............. KF-1A 2,296.0 3,189 186 1,320 1.15 254 0.800 4.5 31.2DST3 ............. KF-1A 2,265.5 3,148 186 1,255 1.15 221 0.793 3.5 31.1Table 27:Summary of Kingfisher-1 Fluid PropertiesThe volumes in Block 3A are being categorised as either Contingent Resources or Prospective Resourcesat this stage of project maturity, and we have therefore used a number of assumptions to construct profilesfor a highly conceptual development of Kingfisher, that would be ‘‘scalable’’ to similar prospects or leads inBlock 3A. These assumptions are given in Table 28.1P 2P 3PRecovery Factor .............................................. 20% 30% 40%Implied Resources (14) (MMstb) .................................... 10 90 424Recovery per well (MMstb) ...................................... 5 7.5 10URR per year ................................................ 9% 9% 10%GOR (scf/stb) ................................................ 235 235 235Table 28:Assumptions Used For Profiles(14) This refers to Kingfisher only.114

RPS EnergyHeritage Oil – Competent Persons ReportThe resulting profiles are shown in Figure 30, below.140,000Oil Rate (stb/d)Cumulative Oil (MMstb)450120,000400350100,000300Oil Rate (stb/d)80,00060,000250200150Cumulative Oil (MMstb)40,00010020,000500020082010201220142016201820202022202420262028203020322034203620382040204220443P Rate 2P Rate 3P Rate 1P Rate 3P Cumulative 2P Cumulative 1P CumulativeFigure 30:Generic, Scalable Profile for Block 3A Prospects22FEB2008034342645.7.2. Production Profiles for Block 1 ProspectsA similar approach was used to generate generic, scalable profiles for prospects & lads in Block 1, but wehave made the assumption that recovery may be lower as a result of a potentially heavier oil at the muchshallower depths. The profile (with STOIIP = 250 MMstb) is shown in Figure 31, below.16,000Oil Rate (stb/d)Cumulative Oli Rate (MMstb)7014,0006012,0005010,000408,000306,0004,000202,0000200820102012201420162018Figure 31:202020222024Rate202620282030Cumulative20322034203620382040Generic, Scalable Profile for Block 1 Prospects & Leads10022FEB200803434419115

RPS EnergyHeritage Oil – Competent Persons Report6. KURDISTAN—MIRAN BLOCKThe Miran Block is located in the highly petroliferous Chemchemal-Butmah Embayment which forms partof the foothills adjacent to the NW-SE trending Zagros Fold Belt. The Miran Block lies about 60 km to theNE of the super giant Kirkuk oilfield.6.1. Data AvailableExploration of this area is at a very early stage. No seismic data have been acquired and no wells have beendrilled in the block. A satellite image indicating surface topography plus a geological land-useinterpretation based on satellite imagery were the only information available.6.2. GeologyThe 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 TaqTaq oilfield (currently under development) and about 20 km to the NE of the potentially large, but onlylightly appraised, Chemchemal gas condensate discovery.The satellite image interpretation indicates that the Miran structure is an elongate anticlinal feature with aNW-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 LateCretaceous Shiranish and Kometan Formations and the Early Cretaceous Qamchuqa Formation. TheShiranish and Kometan Formations are both limestones with low porosity (

RPS EnergyHeritage Oil – Competent Persons Report6.4. Reservoir EngineeringRPS has created production profiles for input to the Miran economics, based on our knowledge of theoffset fields and other standard, petroleum engineering assumptions. The general assumptions used aregiven in Table 30.Low Medium HighProduction Wells ............... 26 52 79Dry hole wells ................. 3 5 8Water Injection wells ............ 0 13 20Total wells .................... 29 70 107STOIIP (MMstb) ............... 909 1,963 3,511in fracture (MMstb) ............. 236 533 954in Matrix (MMstb) .............. 673 1,430 2,557Recovery estimate .............. 60% of fracture only 60% of fracture + 70% of fracture +15% of Matrix 20% of MatrixReserves (MMstb) .............. 142 534 1179Recovery Factor ................ 0.16 0.27 0.34Peak field oil rate, bopd .......... 50,000 150,000 300,000Ave cum/producer (MMstb/well) .... 5.4 10.3 14.9Associated gas (Bscf) ............ 120 454 1,002Peak field gas rate, MMscf/d ....... 45 130 260Field life (years) ................ 25 30 30Table 30:Assumptions Used in Miran ProfilesRPS 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 forhigh case. The annual well effective decline rate is 26 per cent. for low case with initial well rate at 3,500 stb/d for1 year, 18 per cent. for medium case with initial well rate at 4,000 stb/d for 2 years and 15 per cent. forhigh case with initial well rate at 4,500 for 3 years. These are compared with the previous work onsimilar fields case, with the assumption that production is from fractures only—initial, stabilised wellrate 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 maybe required. Recovery per well assumptions are: ~ 5 MMstb/well for the low case, ~10 MMstb/well for themedium case and ~15 MMstb/well for the high case (which gives the well count).117

RPS EnergyHeritage Oil – Competent Persons ReportThe resulting individual well performance profiles are shown in Figure 32, below.500015.0Average yearly oil rate (stb/d)4000300020001000Low caseMedium caseHigh case12.09.06.03.0Cumulative oil production (MMstb)00.00 5 10 15 20 25 30Production yearFigure 32: Assumed Well Profiles for Miran Wells22FEB2008034345646.5. Facilities and CostsBased on a p50 recoverable volume of 534 MMstb RPS has assumed that a prospect could be tied into theNorthern Iraq Pipeline System which is being planned by a consortium of Oil Companies and Governmententities. The plan is to have several hubs and transfer stations so that any prospects/fields are within arange of 60km of the collection system. The cost of developing Miran would be in the order of S1.2 billionwith operating costs expected to be US$100 MM/annum.7. ECONOMICS7.1. Valuation Assumptions7.1.1. GeneralThe effective date of this report is 30/09/2007 and is used as the discount date for the valuation. All valuesare 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 EnergyHeritage Oil – Competent Persons Report7.1.2. Oil PricesThe valuation has been based on a long term forecast for Brent as shown in Table 31 and Figure 32. Thisforecast represents RPS Energy’s base case forecast. A Low Price Case and High Price Case are alsoshown 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 88.62008 ..................................... 80.0 85.0 90.02009 ..................................... 73.0 82.0 91.02010 ..................................... 68.0 80.0 92.52011 ..................................... 62.0 78.0 95.02012 ..................................... 58.0 77.0 97.42013 ..................................... 55.2 77.3 99.42014 ..................................... 56.3 78.8 101.42015 ..................................... 57.4 80.4 103.42016 ..................................... 58.6 82.0 105.42017 ..................................... 59.8 83.7 107.62018 ..................................... 60.9 85.3 109.72019 ..................................... 62.2 87.0 111.92020 ..................................... 63.4 88.8 114.12021 ..................................... 64.7 90.6 116.42022 onwards ............................... +2% p.a. +2% p.a. +2% p.a.Table 31:RPS Forecast Price CasesThese Low Base and High price forecasts represent US$50/bbl, US$70/bbl and US$90/bbl real long-termoil prices.100.0090.0080.0070.00Brent ($/bbl)60.0050.0040.0030.0020.00Forecast price ($ MOD)10.00Forecast price ($ 2008)0.0022FEB2008034347122008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021Figure 32: RPS Base Forecast Price119

RPS EnergyHeritage Oil – Competent Persons ReportThis forecast price was used as the basis for all other price forecasts required for the valuation. Theseprices are summarised in Table 32. Details of how each price deck was derived can be found in the sectionsbelow for each asset.Oman Russia KurdistanOil Condensate LPG GasBukha/ Bukha/Bukha/ West West West UralsWest West Saudi Saudi Bukha Bukha Bukha Bukha Export KirkukBukha NWS Bukha Propane Butane Propane Butane Gas Gas Blend Domestic BlendYear $/bbl $/bbl $/bbl $/tonne $/tonne $/tonne $/tonne $/MMBTU $/MMBTU $/bbl $/bbl $/bbl2007 . . . . . . . . . . . . . 88.59 85.75 83.05 662.74 675.85 530.19 540.68 0.00 1.00 84.16 42.08 82.392008 . . . . . . . . . . . . . 85.00 82.35 79.65 640.97 653.51 512.77 522.81 0.00 1.00 80.75 40.38 79.052009 . . . . . . . . . . . . . 82.00 79.51 76.81 622.78 634.84 498.22 507.87 0.00 1.00 77.90 38.95 76.262010 . . . . . . . . . . . . . 80.00 77.62 74.92 610.65 622.39 488.52 497.91 0.00 1.00 76.00 38.00 74.402011 . . . . . . . . . . . . . 78.00 75.72 73.02 598.52 609.95 478.82 487.96 0.00 1.00 74.10 37.05 72.542012 . . . . . . . . . . . . . 77.00 74.77 72.07 592.45 603.72 473.96 482.98 0.00 1.00 73.15 36.58 71.612013 . . . . . . . . . . . . . 77.29 75.05 72.35 594.21 605.53 475.37 484.42 0.00 1.00 73.43 36.71 71.882014 . . . . . . . . . . . . . 78.83 76.51 73.81 603.55 615.11 482.84 492.09 0.00 1.00 74.89 37.44 73.312015 . . . . . . . . . . . . . +2%pa +2%pa +2%pa +2%pa +2%pa +2%pa +2%pa 0.00 1.00 +2%pa +2%pa +2%paTable 32:Table of Base Case Forecast Prices7.2. Valuation Methodology7.2.1. Reserves1P, 2P and 3P reserves were valued using spreadsheet based discounted cash flow models. Each model wasbased on the applicable contract terms and a forecast of future production and costs.7.2.2. Contingent and Prospective ResourcesThe 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. Thevaluation therefore involved illustrating the value of a number of notional fields on a recoverable volumevs. value plot as an indication of the potential value of success in this block.7.3. Oman—Block 87.3.1. Fiscal Regime and Contract TermsThe Block 8 Petroleum Agreement was signed in February 1985 and has a Development Period of 30 yearsfrom date of first commercial discovery. There is also an option to extend this for a further 10 years underterms to be negotiated which shall be no less favourable than those under which other oil companies arethen operating in Oman.The extended details of the Block 8 PSC are subject to confidentiality agreements. However, RPS Energyconfirms that it has had full access to the final, signed copy of PSC under the terms of such agreements andthat the commercial terms therein have been built into our economics models. The RPS valuation honoursfully these commercial terms.The commercial structure of the Block 8 PSC is in our opinion, very similar to standard PSC’s with theContractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the totalrevenue) and Profit Oil (shared between the Contractor and the Government based on a fixed percentageof the revenue less any cost oil). There are no royalty payments due under the contract and theContractor’s Income Tax liability is paid by the Government out of its share of Profit Oil.7.3.2. Price Assumptions7.3.2.1. CondensateThe current Bukha condensate contract price for the current month is based on the average mean quotesof APPI NWS oil during the previous month plus the mean of the Platts NWS differential for the month120

RPS EnergyHeritage Oil – Competent Persons Reportprior to that less a discount of US$2.70/bbl. A NSW forecast price was derived from the Brent forecastprice 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 samebasis as the current Bukha condensate contract.7.3.2.2. OilWest Bukha oil has been valued assuming parity with the Brent forecast price.7.3.2.3. GasThere are no gas sales from Bukha, but West Bukha gas has a contract gas price with RAKGAS ofUS$1/MMBTU when Saudi Light is above US$34/bbl.7.3.2.4. LPGLPG’s (Propane and Butane) from Bukha are sold at 80 per cent. of the average price of Saudi Propaneand Butane for the previous month less a 50 per cent. discount to account for RAKGAS share. It has beenassumed that West Bukha LPG’s will be sold on the same basis.7.3.3. Unrecovered CostsThe total amount of unrecovered costs in Block 8 at 30/09/2007 stands at US$35.51 million. The majorityof these costs however relate to the West Bukha development. For the valuation of Bukha on its own anestimate of 5 per cent. of the total was assumed as unrecovered costs. This estimate was providedby Heritage.7.3.4. Valuation Summary—BukhaThe post-tax valuation of the net Heritage share is shown in Table 33 at various discount rates.Post-Tax Net Present ValueEconomic(US$ 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 1.0Proved plus Probable Reserves (2P) ................... 2029 2.8 2.1 1.7 1.4 1.2Proved plus Probable plus Possible Reserves (3P) ......... 2029 3.0 2.3 1.7 1.4 1.2Note 1: Economic limit represents last year of input forecast productionTable 33:Bukha Post-Tax Valuation (Net Heritage Share)Bukha reserves are summarised in Table 34, below.Heritage Net Heritage NetGross Working EntitlementRemaining Interest Reserves at BaseReserves Reserves Case Price Forecast(MMstb) (MMstb) (MMstb)CondensateProved Reserves (1P) ............................. 2.1 0.206 0.094Proved plus Probable Reserves (2P) .................. 2.4 0.243 0.099Proved plus Probable plus Possible Reserves (3P) ......... 2.6 0.260 0.102LPGProved Reserves (1P) ............................. 1.5 0.151 0.035Proved plus Probable Reserves (2P) .................. 2.2 0.225 0.046Proved plus Probable plus Possible Reserves (3P) ......... 2.5 0.253 0.049Table 34:Bukha Reserves Summary121

RPS EnergyHeritage Oil – Competent Persons Report7.3.5. Valuation Summary—West BukhaThe post-tax valuation of the net Heritage share is shown in Table 35 at various discount rates.Post-Tax Net Present ValueEconomic(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 8.7Proved plus Probable Reserves (2P) ................. 2037 39.9 35.1 31.3 28.3 25.7Proved plus Probable plus Possible Reserves (3P) ....... 2037 79.7 68.6 60.2 53.6 48.3Note 1: Economic limit represents last year of input forecast productionTable 35:West Bukha Post-Tax Valuation (Net Heritage Share)West Bukha reserves are summarised in Table 36, below.Heritage Net Heritage NetGross Working EntitlementRemaining Interest Reserves at BaseReserves Reserves Case Price Forecast(MMstb) (MMstb) (MMstb)OilProved Reserves (1P) ............................. 9.1 0.906 0.5280Proved plus Probable Reserves (2P) .................. 20.7 2.1 0.764Proved plus Probable plus Possible Reserves (3P) ......... 39.5 3.9 1.2CondensateProved Reserves (1P) ............................. 3.9 0.390 0.195Proved plus Probable Reserves (2P) .................. 8.0 0.794 0.275Proved plus Probable plus Possible Reserves (3P) ......... 16.1 1.6 0.427LPGProved Reserves (1P) ............................. 5.9 0.594 0.145Proved plus Probable Reserves (2P) .................. 12.3 1.2 0.208Proved plus Probable plus Possible Reserves (3P) ......... 25.4 2.5 0.339GasProved Reserves (1P) ............................. 7.4 0.736 0.510Proved plus Probable Reserves (2P) .................. 47.5 4.8 1.5Proved plus Probable plus Possible Reserves (3P) ......... 90.0 9.0 2.3Table 36:West Bukha Reserves Summary7.3.6. Sensitivity to Oil PriceSensitivity of the NPV 10 of the future net revenue in Bukha to changes in oil price is shown in Table 37.Net Present Value 10 of FutureNet RevenuePrice Case 1P 2P 3P(US$ Million, Money of the Day)Low Price ($50/bbl real) ................................... 1.1 1.3 1.3Base Price ($70/bbl real) ................................... 1.4 1.7 1.7High Price ($90/bbl real) ................................... 1.7 2.1 2.2Table 37:Sensitivity of Bukha NPV 10 to Oil Price122

RPS EnergyHeritage Oil – Competent Persons ReportSensitivity of the NPV 10 of the future net revenue in West Bukha to changes in oil price is shown inTable 38.Net Present Value 10 of FutureNet RevenuePrice Case 1P 2P 3P(US$ Million, Money of the Day)Low Price ($50/bbl real) ................................... 8.6 25.1 48.0Base Price ($70/bbl real) ................................... 11.4 31.3 60.2High Price ($90/bbl real) ................................... 14.3 37.7 72.6Table 38:Sensitivity of West Bukha NPV 10 to Oil Price7.4. Russia—Zapadno Chumpasskoye7.4.1. Fiscal Regime and Contract TermsThe Zapadno Chumpasskoye licence is due to expire in September 2024. The main commercial terms are:Crude Oil Export DutyUrals Urals Rate($/tonne)($/bbl)25 4.00 + 0.65 * (P 25)P = average quarterly price of Urals Blend (US$/bbl)VAT .............................Mineral Extraction Tax (MET) .........Jan 2005—September 2007 ............Assumed from September 2007 .........18 per cent. on domestic salesOILMET = 419 Roubles / tonne * CpWhere Cp = (P 9) * (R / 261)P = average quarterly price of Urals Blend (US$/bbl)R = average quarterly exchange rate for US$/Rouble16.50 per cent.Tax base—Revenue less VAT, excise tax, custom duties,transportation costs and insurance costsProperty Tax ...................... 2.2 per cent.Tax base—Cumulative Capex (drilling and facilities) lessdepreciationIncome / Profits Tax ................. 24.0%Tax base—Revenue less Opex, depreciation, interest,exchangerate losses and losses on re-evaluation.Depreciation:Facilities: 7-10 yearsDrilling: 10-15 yearsPipelines: 20-25 yearsLoss carry forward—10 years123

RPS EnergyHeritage Oil – Competent Persons Report7.4.2. Price AssumptionsHeritage has assumed that the gross field production will be split between export (via Black Sea) anddomestic sales in the proportion 35 per cent./65 per cent. respectively. The export price has been based onthe Urals (Mediterranean) price. This has been derived from the Brent forecast using a relationship basedon an analysis of historical prices. A 5 per cent. discount to Brent has been assumed for the valuation. Thedomestic price was assumed to be 50% of the Urals price.$100.0$90.0$80.0URALS (Mediterranean), $/bbl$70.0$60.0$50.0$40.0$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 $100.0Brent ($/bbl)Figure 33: Plot of Brent vs. URALS (Mediterranean)—1997 to 200722FEB2008034351817.4.3. Transportation CostsEstimates of the transportation costs for export via the Transneft pipeline system and for domestic saleswere provided by Heritage Oil and Gas. A figure of US$4.53/bbl was used for export costs and US$1.78/bblfor domestic transportation costs.7.4.4. Tax LossesThe total tax loss carry forward at 30/09/2007 of US$22.5 MM was included in the valuation as a deductionagainst future profits tax liabilities. This sum was provided by Heritage.7.4.5. Valuation SummaryAlthough the licence expiry date is 2024, the value and reserves have been reported up to their economiclimit on the assumption that the licence will be extended full economic recovery of all the reserves. Thevaluation includes the cost of abandonment of the wells and all facilities, which has been estimated to beUS$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 ValueEconomic(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 32.9Proved plus Probable Reserves (2P) ........... 2029 413.6 308.0 226.6 163.5 46.7Proved plus Probable plus Possible Reserves (3P) . 2031 1356.2 1013.7 762.2 574.5 238.2Table 39:Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share)124

RPS EnergyHeritage Oil – Competent Persons ReportZapadno Chumpasskoye reserves are summarised in Table 40, below.Heritage Net Heritage NetGross Working EntitlementRemaining Interest Reserves at BaseReserves Reserves Case Price Forecast(MMstb) (MMstb) (MMstb)OilProved Reserves (1P) ............................. 24.4 23.1 23.1Proved plus Probable Reserves (2P) .................. 63.6 60.5 60.5Proved plus Probable plus Possible Reserves (3P) ......... 169.9 161.4 161.4Table 40:Zapadno Chumpasskoye Reserves Summary7.4.6. Sensitivity to Oil PriceSensitivity of the NPV 10 of the future net revenue in Zapadno Chumpasskoye to changes in oil price isshown in Table 41.Net Present Value 10 of Future Net RevenuePrice Case 1P 2P 3P(US$ Million, Money of the Day)Low Price ($50/bbl real) .............................. 46.2 71.4 378.4Base Price ($70/bbl real) .............................. 17.5 226.6 762.2High Price ($90/bbl real) .............................. 80.6 383.0 1,150.0Table 41:Sensitivity of Zapadno Chumpasskoye NPV 10 to Oil Price7.5. KURDISTAN—Miran Block7.5.1. Fiscal Regime and Contract TermsThe Miran Block was signed in October 2007. The exploration period is 5 years in duration and issubdivided into an initial sub-period of 3 years with the option of a second sub-period of 2 years. Thedevelopment 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 Energyconfirms that it has had full access to the final, signed copy of PSC under the terms of such agreements andthat the commercial terms therein have been built into our economics models. The RPS valuation honoursfully these commercial terms.The commercial structure of the Block 8 PSC is in our opinion very similar to standard PSC’s with theContractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the netrevenue) and Profit Oil (shared between the Contractor and the Government based on a R factor, theR factor being defined as the ratio of cumulative revenue divided by cumulative costs). A royalty paymentis 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 whencommerciality is declared, but is not required to make any repayment to the Contractor for costs incurredup to that point.7.5.2. Price AssumptionsFor 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 Brent125

RPS EnergyHeritage Oil – Competent Persons Report7.5.3. Valuation summaryIn the absence of any data upon which to assess the potential of the Miran contract area the range inpossible value has been illustrated in the figure below. This plot demonstrates the possible range inunrisked NPV 10 (net to Heritage) for a range of notional field sizes and could be used as an indicator ofthe possible value of the contract area. Curves are presented for a low and high oil price in addition to theBase Case price forecast.$4,500NPV10 Net to Heritage, MMUS$$4,000$3,500$3,000$2,500$2,000$1,500$1,000High price ($90/bbl)Base price ($70/bbl)Low price ($50/bbl)$500$0- 200 400 600 800 1,000 1,200Gross Recoverable Oil, Economic Life of Contract, MMstbFigure 34: Heritage Net NPV 10 vs. Notional Field Size Showing Price Sensitivity28FEB200808431129Net NPV 10 and average for NPV 10c per barrel for the Base Case oil price forecast are given in Table 42for the range of recoverable volumes based on the notional field sizes RPS has assumed.Net NPV 10 and Average forNPV 10 /stb at Base Case PriceForecastsLow Case Mid Case High CaseGross Recoverable Oil Volume (MMstb) ....................... 138 520 1,138NPV 10 Net to Heritage (US$MM) ............................ 413 1,366 2,952Average NPV 10 /stb ......................................US$2.6Table 42:Net NPV 10 and Average for NPV 10 /stb for a Range of Notional Field Sizes126

RPS EnergyHeritage Oil – Competent Persons ReportAPPENDIX A:1P2P3PAAPGAPIBBargbblsbopdB o(g)iBscfBtuGLOSSARY OF TECHNICAL TERMSProvedProved plus ProbableProved plus Probable plus PossibleAmerican Association of Petroleum GeologistsAmerican Petroleum InstituteBilliongauge pressure in Barbarrelsbarrels of oil per dayinitial formation volume factor for oil (or gas)billion standard cubic feetBritish Thermal Units(i/n)C n (isomeric or normal) hydrocarbon of the general form C n H 2n+2C 1C 1 H 4 , methaneC 3C 3 H 8 , propaneC 4C 4 H 10 , butaneC 7 (+)C 7 H 16 , heptane (plus, meaning heptane and all heavier fractions))CGRCondensate: Gas RatioCO 2carbon dioxideCoSChance of SuccessCVDConstant Volume Depletion (a laboratory experiment)DSTdrill stem testEntitlement Volumes the volumes of oil and/or gas which a Contractor receives under the termsof a PSAEoSEquation of StateFBHPflowing bottom hole pressureFFDFull Field DevelopmentftFeetFVF Formation Volume Factor (also: B oi )FWHPflowing well head pressureG&AGeneral & AdministrativeGIIPGas Initially In PlaceGOCGas-oil contactGORGas: Oil RatioGRVgross rock volumeH 2 Shydrogen sulphideLPGLiquefied Petroleum Gas—in this context means either Butane or Propaneor bothk (e)(effective) permeabilitykgkilogramkmkilometremmetresMThousandMDmeasured depth127

RPS EnergymDMMMbblsMMBtu/dMMbwpdMMscfd or MMscf/dMMstbMoney of the DayMPaN 2N:GNIOCOWCPIp (b/r)PSC / PSApsi(a/g)PTAPVTRFR siR wSscfSPESTOIIPS wTDT rTVDTVDSSURRVCLVRRVSHWHFPWorking Interest ShareWPCm Heritage Oil – Competent Persons Reportpermeability in milli-DarciesMillionthousand barrelsmillions of British Thermal Units per daymillion barrels of water per daymillions of standard cubit feet per daymillion stock tank barrelscalculated allowing for the effect of inflationMega PascalNitrogenNet to gross ratioNational Iranian Oil Companyoil-water contactProductivity Index (stb/d/psi)(bubble point or reservoir) pressureProduction Sharing Contract / Production Sharing Agreementpounds per square inch (absolute/gauge)Pressure transient analysisPressure, Volume & TemperatureRecovery FactorSolution GORWater resistivitySkin, a measure of damage derived from well test analysisstandard cubic feet measured at 14.7 pounds per square inch and 60 FSociety of Petroleum EngineersStock Tank Oil Initially In PlaceWater SaturationTotal DepthReservoir temperatureTrue vertical depthtrue vertical depth (sub-sea)Ultimate recoverable reserves (before economic cut-off)Volume of clayVoidage replacement ratioVolume of shaleWellhead Flowing Pressure(of reserves) calculated by multiplying the Gross estimate by theContractor’s Working Interest in a Production Sharing ContractWorld Petroleum CongressOhm-metreOmega, a measure of fracture storageLambda, a measure of matrix-fracture flowOil densityOil viscosity128

RPS EnergyHeritage Oil – Competent Persons ReportAPPENDIX 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 thathave an inherent degree of uncertainty. These quantities are associated with development projects atvarious stages of design and implementation. Use of a consistent classification system enhancescomparisons between projects, groups of projects, and total company portfolios according to forecastproduction profiles and recoveries. Such a system must consider both technical and commercial factorsthat impact the project’s economic feasibility, its productive life, and its related cash flowsPetroleum Resources Classification FrameworkPetroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, orsolid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbondioxide, nitrogen, hydrogen sulphide and sulphur. In rare cases, non-hydrocarbon content could be greaterthan 50 per cent.The term ‘‘resources’’ as used herein is intended to encompass all quantities of petroleum naturallyoccurring 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 currentlyconsidered ‘‘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.PRODUCTIONTOTAL PETROLEUM INITIALLY-IN-PLACE (PIP)DISCOVERED PIIPUNDISCOVEREDPIIPSUB-COMMERCIAL COMMERCIAL1P 2P 3P1CRESERVESProved Probable PossibleLowEstimateCONTINGENTRESOURCES2CUNRECOVERABLEPROSPECTIVERESOURCESBestEstimateUNRECOVERABLE3CHighEstimateIncreasing Chance of CommercialityRange of UncertaintyResources Classification Framework18MAR200800130115129

RPS EnergyHeritage Oil – Competent Persons ReportThe ‘‘Range of Uncertainty’’ reflects a range of estimated quantities potentially recoverable from anaccumulation by a project, while the vertical axis represents the ‘‘Chance of Commerciality’’, that is, thechance that the project that will be developed and reach commercial producing status. The followingdefinitions apply to the major subdivisions within the resources classification:TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to existoriginally in naturally occurring accumulations. It includes that quantity of petroleum that isestimated, as of a given date, to be contained in known accumulations prior to production plus thoseestimated 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 salesproduct specifications, raw production (sales plus non-sales) quantities are also measured andrequired to support engineering analyses based on reservoir voidage.Multiple development projects may be applied to each known accumulation, and each project will recoveran estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercialand Sub-Commercial, with the estimated recoverable quantities being classified as Reserves andContingent Resources respectively, as defined below.RESERVES are those quantities of petroleum anticipated to be commercially recoverable byapplication of development projects to known accumulations from a given date forward underdefined conditions. Reserves must further satisfy four criteria: they must be discovered,recoverable, commercial, and remaining (as of the evaluation date) based on the developmentproject(s) applied. Reserves are further categorized in accordance with the level of certaintyassociated with the estimates and may be sub-classified based on project maturity and/orcharacterized by development and production status.CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, tobe potentially recoverable from known accumulations, but the applied project(s) are not yetconsidered mature enough for commercial development due to one or more contingencies.Contingent Resources may include, for example, projects for which there are currently no viablemarkets, or where commercial recovery is dependent on technology under development, or whereevaluation of the accumulation is insufficient to clearly assess commerciality. ContingentResources are further categorized in accordance with the level of certainty associated with theestimates and may be sub classified based on project maturity and/or characterized by theireconomic status.UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, asof 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, tobe potentially recoverable from undiscovered accumulations by application of futuredevelopment projects. Prospective Resources have both an associated chance of discovery and achance of development. Prospective Resources are further subdivided in accordance with thelevel of certainty associated with recoverable estimates assuming their discovery and developmentand may be sub-classified based on project maturity.UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Placequantities 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 circumstanceschange or technological developments occur; the remaining portion may never be recovered due tophysical/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 anyaccumulation or group of accumulations (discovered or undiscovered) to define those quantities ofpetroleum estimated, as of a given date, to be potentially recoverable under defined technical andcommercial conditions plus those quantities already produced (total of recoverable resources).In specialized areas, such as basin potential studies, alternative terminology has been used; the totalresources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total recoverable or130

RPS EnergyHeritage Oil – Competent Persons ReportEUR may be termed Basin Potential. The sum of Reserves, Contingent Resources, and ProspectiveResources may be referred to as ‘‘remaining recoverable resources.’’ When such terms are used, it isimportant that each classification component of the summation also be provided. Moreover, thesequantities should not be aggregated without due consideration of the varying degrees of technical andcommercial risk involved with their classification.Range of UncertaintyThe range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented byeither deterministic scenarios or by a probability distribution. When the range of uncertainty is representedby 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 willequal or exceed the low estimate. There should be at least a 50 per cent. probability (p50) that the quantities actually recovered willequal or exceed the best estimate. There should be at least a 10 per cent. probability (p10) that the quantities actually recovered willequal 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 consistentinterpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at eachlevel of uncertainty are estimated discretely and separately.Reserves CategoriesThe following summarizes the definitions for each Reserves category in terms of both the deterministicincremental approach and scenario approach and also provides the probability criteria if probabilisticmethods are applied. Proved Reserves (P1) are those quantities of petroleum, which, by analysis of geoscience andengineering data, can be estimated with reasonable certainty to be commercially recoverable, from agiven date forward, from known reservoirs and under defined economic conditions, operatingmethods, and government regulations. If deterministic methods are used, the term reasonablecertainty is intended to express a high degree of confidence that the quantities will be recovered. Ifprobabilistic methods are used, there should be at least a 90 per cent. probability that the quantitiesactually recovered will equal or exceed the estimate. Probable Reserves are those additional Reserves which analysis of geoscience and engineering dataindicate are less likely to be recovered than Proved Reserves but more certain to be recovered thanPossible Reserves. It is equally likely that actual remaining quantities recovered will be greater than orless than the sum of the estimated Proved plus Probable Reserves (2P). In this context, whenprobabilistic methods are used, there should be at least a 50 per cent. probability that the actualquantities recovered will equal or exceed the 2P estimate. Possible Reserves are those additional reserves which analysis of geoscience and engineering datasuggest are less likely to be recoverable than Probable Reserves. The total quantities ultimatelyrecovered from the project have a low probability to exceed the sum of Proved plus Probable plusPossible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, whenprobabilistic methods are used, there should be at least a 10 per cent. probability that the actualquantities recovered will equal or exceed the 3P estimate.Use of consistent terminology promotes clarity in communication of evaluation results. For Reserves, thegeneral cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associatedincremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must beviewed within context of, the complete resources classification system. While the categorization criteria areproposed specifically for Reserves, in most cases, they can be equally applied to Contingent andProspective 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/3Crespectively. 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 INFORMATIONSet out below is the Group’s summary financial information for the periods indicated. As this is only asummary, investors are advised to read the whole of this document and not rely on the informationsummarised here.Summary Consolidated Income Statements (for the nine-month period ended 30 September 2007 andfinancial years 2005 and 2006 prepared in accordance with IFRS and audited and for the nine-monthperiod ended 30 September 2006 prepared in accordance with IFRS and unaudited)Year endedNine-month periods31 December ended 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Net revenue .......................... 1,184,125 6,834,239 5,475,430 2,843,053Net expenses .......................... (12,795,257) (19,689,292) (12,646,009) (41,150,721)Gain on disposal of subsidiaries ............ — — — 1,077,132Finance income (costs) .................. (161,534) (27,961,892) (7,764,647) (30,251,946)Income from and gain on disposal ofdiscontinued operations ................ 3,510,441 12,449,190 2,417,316 —Net loss for the period attributable to equityholders of the Corporation .............. (8,262,225) (28,367,755) (12,517,910) (67,482,482)Net earnings per share from discontinuedoperationsBasic and diluted ....................... 0.16 0.57 0.11 —Net loss per share from continuing operationsBasic and diluted ....................... (0.54) (1.86) (0.68) (3.02)Net loss per shareBasic and diluted ....................... (0.38) (1.29) (0.57) (3.02)132

Summary Consolidated Balance Sheets (at 30 September 2007 and 31 December 2005 and 2006prepared in accordance with IFRS and audited and at 30 September 2006 prepared in accordance withIFRS and unaudited)31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)AssetsNon-current assetsAssets held for sale ..................... — — 16,962,091 —Intangible exploration assets ............... 43,503,704 54,767,332 45,602,140 85,746,870Intangible development costs .............. 1,187,371 1,574,039 1,346,858 —Property, plant and equipment ............. 25,282,552 32,187,098 25,546,939 59,105,312Other financial assets .................... — 914,558 — 4,200,90969,973,627 89,443,027 89,458,028 149,053,091Current assetsAssets held for sale ..................... — — 425,412 —Inventories ........................... 251,915 98,921 211,510 79,768Prepaid expenses ....................... 219,222 531,273 515,899 340,402Trade and other receivables ............... 1,318,450 9,839,506 664,953 6,455,303Cash and cash equivalents ................ 8,583,321 46,861,146 46,851,571 61,894,71110,372,908 57,330,846 48,669,345 68,770,18480,346,535 146,773,873 138,127,373 217,823,275LiabilitiesCurrent liabilitiesTrade and other payables ................. 4,438,649 12,715,381 9,396,651 15,781,606Borrowings ........................... 248,045 147,720 140,352 160,224Liabilities of disposal group held for sale ..... — — 807,208 —4,686,694 12,863,101 10,344,211 15,941,830Non-current liabilitiesBorrowings ........................... 7,520,438 63,124,843 62,512,234 144,918,765Derivative financial liability ............... — 27,997,140 8,621,068 32,810,103Provisions ............................ 434,849 62,322 — 133,274Liabilities of disposal group held for sale ..... — — 419,770 —7,955,287 91,184,305 71,553,072 177,862,14212,641,981 104,047,406 81,897,283 193,803,97267,704,554 42,726,467 56,230,090 24,019,303Shareholders’ Equity Attributable to EquityHolders of the CorporationShare capital .......................... 22,854,418 24,580,984 23,508,025 40,910,098Reserves ............................. 973,956 2,637,058 1,363,795 35,083,262Retained earnings (deficit) ................ 43,876,180 15,508,425 31,358,270 (51,974,057)67,704,554 42,726,467 56,230,090 24,019,303133

Summary Consolidated Cashflow Statements (for the nine-month period ended 30 September 2007 andfinancial years 2005 and 2006 prepared in accordance with IFRS and audited and for the nine-monthperiod ended 30 September 2006 prepared in accordance with IFRS and unaudited)Year endedNine-month periods31 December ended 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Cash used in operating activities ............ (7,854,323) (12,737,451) (8,331,393) (7,212,661)Cash used in investing activities ............ (11,946,720) (28,823,833) (12,074,902) (53,535,576)Cash provided by financing activities ......... 9,020,147 58,031,186 57,356,469 75,080,072Cash provided by discontinued operations ..... 4,313,817 21,324,969 1,009,595 —(Decrease) increase in cash and cashequivalents .......................... (6,467,079) 37,794,871 37,959,769 14,331,835Cash and cash equivalents—beginning of period 16,235,523 8,583,321 8,583,321 46,861,146Foreign exchange (loss) gain on cash held inforeign currency ...................... (1,185,123) 482,954 308,481 701,730Cash and cash equivalents—end of period ..... 8,583,321 46,861,146 46,851,571 61,894,711Summary Consolidated Income Statements (for financial years 2005 and 2004 prepared in accordancewith Canadian GAAP and audited)2004 2005$ $Net revenue ............................................... 6,596,982 8,013,722Net 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 52,434,857Other .................................................... 41,677 (740,879)Retained earnings—end of year ................................. 52,434,857 47,894,165Net 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 withCanadian GAAP and audited)Assets2005 2004$ $Current AssetsCash and cash equivalents .................................... 8,583,321 16,235,523Accounts receivable ......................................... 1,318,450 4,640,802Note receivable ............................................ — 4,280,161Inventories ............................................... 216,474 94,483Prepaid expenses ........................................... 219,222 272,16810,337,467 25,523,137Property and equipment ....................................... 72,382,935 54,083,097Deferred development costs .................................... 1,187,371 1,013,01283,907,773 80,619,246Liability and Shareholders’ EquityCurrent LiabilitiesAccounts payable and accrued liabilities .......................... 4,438,649 6,397,247Current portion of long-term debt .............................. 248,045 —4,686,694 6,397,247Long-term debt ............................................. 7,520,438 —Asset retirement obligations .................................... 434,849 328,553Shareholders’ Equity:Share capital and warrants .................................... 22,854,418 21,434,168Contributed surplus ......................................... 517,209 24,421Retained earnings .......................................... 47,894,165 52,434,85771,265,792 73,893,44683,907,773 80,619,246Summary Consolidated Cashflow Statements (for financial years 2005 and 2004 prepared inaccordance with Canadian GAAP and audited)2005 2004$ $Cash used in operating activities ................................ 697,123 1,866,009Cash used in investing activities ................................ (16,184,349) (11,310,312)Cash provided by financing activities ............................. 9,020,147 604,953Foreign exchange gains (losses) on cash held in foreign currency ......... (1,185,123) 906,001Decrease in cash and cash equivalents ............................ (7,652,202) (7,933,349)Cash and cash equivalents—beginning of year ...................... 16,235,523 24,168,872Cash and cash equivalents—end of year .......................... 8,583,321 16,235,523135

PART V—OPERATING AND FINANCIAL REVIEWThe following discussion and analysis is intended to assist in the understanding and assessment of the trendsand significant changes in the Group’s results of operations and financial condition. Historical results may notbe indicative of future financial performance. Forward-looking statements contained in this review that reflectthe current view of management involves risks and uncertainties and are subject to a variety of factors that couldcause actual results to differ materially from those contemplated by such statements. Factors that may causesuch a difference include, but are not limited to, those discussed in ‘‘Forward-Looking Statements’’ and ‘‘RiskFactors’’. In this document the consolidated financial statements presented are those of the Group. Thisdiscussion is based on the consolidated financial statements of the Group and should be read in conjunctionwith its consolidated financial statements and the accompanying notes contained in Part VI ‘‘FinancialInformation’’ and with the information relating to the business of the Group included elsewhere in thisdocument. Unless otherwise indicated, all of the financial data and discussions thereof are based upon financialstatements prepared in accordance with IFRS. Investors should read the whole of this document and not relyjust on summarised information.1. OVERVIEWThe Company was incorporated on 6 February 2008. The Group was established in 1992 (with HOC beingincorporated on 30 October 1996) and commenced trading in the mid-1990s as an independent upstreamexploration and production group engaged in the exploration for, and the development, production andacquisition of, oil and gas interests in Africa, the Middle East, Russia and the Mediterranean. The Grouphas producing properties in Oman and Russia and exploration projects in Uganda, the KRI, the DRC,Malta, Pakistan and Mali.RussiaThe Group has a 95 per cent. interest in a development project the Zapadno Chumpasskoye licence inRussia, which has proved and probable reserves of 60.5 million bbls net to the Group. Productioncommenced 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 averaged342 bopd in February 2008. Planning of the design and specification of the field development facilitiesis ongoing.OmanThe Group has a 10 per cent. working interest in Block 8 in Oman. Block 8 includes Bukha, a producinggas-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 tore-enter and complete it as a producing well. The oil was light (approximately 42 o API). Development ofthe West Bukha field has commenced and comprises design, fabrication and installation of the wellheadplatform and pipeline. Production is targeted for the third quarter of 2008. The West Bukha-3 productionwell is planned to be drilled in mid-2008.UgandaThe Group is the operator and has a 50 per cent. interest in two exploration licences in Uganda (Blocks 3Aand 1). The Kingfisher deviated well in Block 3A was drilled to a total depth of 3,195 metres. Drilling wascompleted in March 2007. Four intervals were tested successfully in the Kingfisher well, resulting in anoverall cumulative maximum flow rate of 13,893 bopd. The test produced quality light (between 30 and32 API) and sweet oils with a low gas-oil ratio and some associated wax. The sandstone reservoirs exhibithigh permeability up to 3,000 milliDarcies. The Kingfisher-2 well is scheduled to spud in the first halfof 2008. Blocks 3A and 1 include minimum drilling and seismic commitments which the Group expects toachieve in 2008.DRCThe Group signed a PSC in the DRC in the summer of 2006 for a 39.5 per cent., non-operated interest inBlocks 1 and 2 covering over 6,000 square km of onshore and offshore acreage in the DRC part of theAlbert Basin. An exploration programme, the timing of which is uncertain, will only commence following apresidential decree ratifying the DRC PSC. The minimum work programme in the DRC PSC for the two136

locks during the first three and a half year term includes the acquisition of 2D seismic and the drilling oftwo exploration wells, at a minimum gross cost of more than $10.275 million. The exploration termcommences on receipt of the presidential decree.KRGThe Group has executed a PSC with the KRG over the Miran Block in the south-west of the KRI. TheGroup also agreed to be a 50/50 partner with the KRG to design and build a 20,000 bopd oil refinery in thevicinity of the licence area. Under the terms of the agreement, Heritage Middle East, a wholly-ownedsubsidiary of the Company, will serve as operator. The Miran licence area is 1,015 square km andencompasses a structure as expressed at surface which constitutes an area of approximately 500 square kmand appears to have three separate culminations. Reservoir potential exists at numerous zones thatmanagement estimate could contain significant quantities of oil. The minimum work programme in thePSC during the first three year term comprises the acquisition of 2D seismic and the drilling of oneexploration well, at a minimum cost of more than $8.5 million.MaliThe Group farmed-in to two onshore exploration licences in Mali, in North-West Africa, with a gross areaof over 72,000 square km in November 2007. The Group has been appointed as operator. The Group hasthe right to acquire a 75 per cent. working interest in each of Block 7 and Block 11 from Centric EnergyCorporation in return for funding the working interest. The Group will fund all costs of the obligatorywork programmes for the next two years in both blocks, comprising the acquisition of 2D seismic and thedrilling of one exploration well, at a total estimated cost for the two licences of between $15 million and$20 million.MaltaThe Group was awarded 100 per cent. of Areas 2 and 7 offshore to Malta in December 2007. The licenceareas 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. Theminimum work programme in the PSC during the first three year term comprises the acquisition of 2Dseismic and the drilling of one exploration well, at a minimum cost in excess of $22 million.PakistanA wholly-owned subsidiary of the Group was awarded a 60 per cent. participating interest in the SanjawiBlock (No. 3068-2) in Zone II (Baluchistan), in Pakistan. The onshore exploration licence has a gross areaof 2,258 square km. The exploration licence and PSC were executed on 16 November 2007. The Group hasbeen appointed operator. The joint venture partners are two companies incorporated in Pakistan, SprintEnergy (Pvt) Limited, a subsidiary of the JS Group, and Trakker Energy (Pvt) Limited.2. ACQUISITIONS, DISPOSALS AND FINANCINGThe Group’s portfolio and financial position has changed in several material aspects over the last threeyears, including the following principal changes.Year Ended 31 December 2004In 2004, the Group was awarded a 50 per cent. working interest in Blocks 3A and 1 in the Albert Basin inUganda, and was appointed operator in both blocks. Block 3A, which ordinarily encompassed most of theexploration acreage which previously constituted Block 3, which had been awarded in 1997 and afterdrilling three test wells at the same Turaco drill site, which were not considered commercial discoveries, itwas subsequently relinquished, was re-licensed in 2004 for a term of six years and now covers an area of2,033 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 acquirethe overriding royalty in the Congo for proceeds of $30.4 million by 30 July 2004. An additional contingentconsideration of up to A8.3 million (approximately $10 million) was payable on the sale of all or a portionof the interest by the purchaser by 31 December 2005, although this did not take place. Concurrent withthe exercise of the option, the purchaser would be required to sell a seven per cent. working interest in137

another oil and gas interest in the Congo to the Group for $7 million. The purchaser exercised its optionon 30 June 2004.In 2003, the Group acquired a 33 per cent. interest in Pipelay and Naturalay Technologies and on24 September 2004, acquired an additional 31.7 per cent. interest. Pipelay is a technology company whosepurpose is to hold and market technology relating to the Buoyant Drum Lay System. Patent protection forthe design has been secured and is held in Pipelay’s sister company, Naturalay Technologies. This systemcomprises a vessel, with a large drum floating in a moon pool.Year Ended 31 December 2005In 2005, the Group acquired a 95 per cent. equity interest in ChumpassNefteDobycha, a Russian companywhose sole asset is the Zapadno Chumpasskoye licence, an exploration and production permit previouslyheld by TNK-BP. The licence, which expires on 7 September 2024, is located in West Siberia in the provinceof Khanty-Mansiysk. A total of nine wells had been drilled on the licence prior to the acquisition by theGroup. The licence is located in an extremely hydrocarbon-rich province close to well-developedinfrastructure; a federal oil pipeline runs through the licence to which the Group has certain access rightsand there is railway access nearby.Year Ended 31 December 2006In March, 2006, HOC issued 600 unsecured convertible bonds each with a par value of $100,000 foraggregate proceeds of $60 million. The bonds had a coupon rate of 10 per cent. per annum, a term of fiveyears and one day and were convertible into HOC Common Shares at a price of $18 per share. HOC hadthe right to redeem, in whole or part, the bonds for cash at any time on or before 28 March 2007 at150 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 to31 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 and2 in the prospective Albert Basin. Blocks 1 and 2 cover in excess of 6,000 square km over the onshore andoffshore 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 of3,195 metres. Four intervals were tested successfully in the Kingfisher well, resulting in an overallcumulative flow rate of 13,893 bopd through a one inch choke. Drilling and testing were completed inMarch 2007.In the last quarter of 2006, the Group entered into an agreement with TISE Holding Company to establisha jointly owned company, TISE-Heritage Neftegas, to appraise and jointly acquire oil and gasopportunities in Russia and internationally. Shareholders of TISE Holding Company include Concord,Zarubejneft, Zarubejneftegas (a wholly-owned Gazprom subsidiary), Technopromexport andZarubejstroymontaj.In November 2006, Heritage Congo was sold to Afren for a consideration of $21 million, plus 1.5 millionAfren warrants, with a term of five years and an exercise price of £0.60 per share. Heritage Congo held a14 per cent. interest in the Noumbi permit, in the Congo.Period ended 30 September 2007On 18 January 2007, the Group finalised the statement of adjustments relating to the sale of its25 per cent. working interest in the Kouakouala A and 30 per cent. working interest in the Kouakouala Blicence in the Congo to the other partners in the licences, Maurel et Prom and Burren Energy, for thefollowing 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 licencein 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 NaturalayTechnologies 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 ofthe KRI and a separate strategic agreement under which the Group will be a 50/50 partner with the KRGin designing and building a 20,000 bopd oil refinery in the vicinity of the licence area. Under the terms ofthe 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 grossarea 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-WestAfrica, with a gross area of over 72,000 square km. The Group has been appointed as operator. Whollyownedsubsidiaries of the Group have the right to acquire a 75 per cent. working interest in Block 7 andBlock 11 from Mali Oil Developments SARL, a wholly-owned subsidiary of the public company CentricEnergy Corporation.On 14 December 2007, the Group executed a PSC with the Maltese Government for Areas 2 and 7 in thesoutheastern offshore region of Malta. Under the terms of the agreement, Heritage Oil InternationalMalta 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 reviewthrough the disposal of its interests in the Congo and two rounds of convertible bond issues and an equityfinancing.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 yearsand one day and an annual coupon of 8 per cent. The bonds are convertible into HOC Common Shares ata price of $47 per share. HOC had the right to redeem, in whole or part, the bonds for cash at any time onor before 16 February 2008, at 150 per cent. of par value, although this right was not exercised. Proceedswere partly used to finance the redemption of the outstanding $55 million of convertible bonds at apremium of 150 per cent. On 17 January 2007, HOC gave notice that it had exercised its option to redeemthe 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 millionfrom the issue of 3 million HOC Common Shares by way of a private placement with institutionalinvestors.3. KEY FACTORS AFFECTING THE GROUP’S RESULTS OF OPERATIONS AND FINANCIALCONDITIONThe key factors affecting the Group’s results of operations and financial condition during the periodsunder review and that the Group expects will continue to have a significant effect on its results ofoperations 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 ratesOil and gas exploration involves a high degree of risk and there is no assurance that expenditures made onfuture exploration by the Group will result in new discoveries of oil or gas in commercial quantities orat all.The principal expenditures related to the Group’s exploration work programmes are the acquisition ofseismic data and the drilling of wells. When entering a new geological province and when drilling a newexploration prospect, the Group assesses the exploration risk involved and offsets that risk against thepotential monetary gain in the event of success. The Group also reduces the potential risk by undertakingthorough exploration work as well as, in certain instances, exploring in known hydrocarbon provinces.139

Factors associated with operating in developing countries, political and regulatory instabilityCertain of the Group’s interests are located in developing countries, some of which have historicallyexperienced periods of civil unrest, terrorism, violence and war, as well as political and economicinstability.Wherever it operates the Group assesses all the significant operational challenges involved and plansaccordingly. 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 employinglocal labour.Oil and gas sales volumes and pricesBoth oil and gas prices are unstable and are subject to fluctuation and subject to various factors beyond theGroup’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 ended30 September 2007 the Group did not enter into any hedging arrangements.Reliance on key employeesThe recruitment and retention of skilled personnel has become a key issue for the oil and gas industry, withsignificant competition existing for skilled personnel. Skilled personnel are required in the areas ofexploration 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 andchallenging and satisfying work, with a competitive remuneration package. The Company is therefore ableto attract and retain high quality staff. The Group has a number of strategies in place for reinforcing itscapabilities, including training and developing local skills and for example has entered into a number ofscholarship schemes in Uganda.4. OPERATIONAL PERFORMANCEProducing assetsOil and gas revenue was generated from the Group’s 10 per cent. working interest in the Bukha field, inBlock 8, Oman, during the years ended 31 December 2005 and 2006 and the nine-month period ended30 September 2007. The Bukha field produces gas, for which the Group derives no revenue, condensateand LPG. The Group’s average net share of liquids (condensate and LPG) has varied from between 140and 172 bopd during the period under review. The development of the West Bukha field in Block 8, Omancontinues to advance. Field development is ongoing and production from the West Bukha field is expectedby management to commence in the third quarter of 2008.Crude oil production from the Zapadno Chumpasskoye field in Russia commenced on 14 May 2007 andaveraged 362 bopd in the four months ended 30 September 2007. Production averaged 342 bopd inFebruary 2008.Exploration and appraisal assetsThe Group has experienced considerable exploration success in Uganda and work programmes have beenaccelerated following the discovery of a new hydrocarbon system in the Albert Basin. This discoveryincludes the Kingfisher-1 discovery well that was completed in March 2007, which production tested atrates of approximately 13,900 bopd. 3D and 2D seismic programmes have identified a number of targets inBlocks 3A and 1, for which multi-well drilling programmes are planned to commence in the first half of2008. 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 horizonnot reached by previous Kingfisher drilling.A 2D seismic survey is also being carried out on in Block 1, Uganda, where relatively shallow structureshave been identified with associated amplitude anomalies. Oil is known to have migrated into Block 1, asevidenced by the active oil seep located within the block at Paraa. This oil seep together with the presence140

of amplitude anomalies, further supports the potential presence of hydrocarbons within the block. Anexploration drilling programme is scheduled to commence in or after the summer of 2008, concentrated onthe 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 inthe southern part of the KRI. The Group has also entered into a separate strategic agreement with theKRG to establish a 50/50 joint venture company which shall build, own and operate an oil refinery in thevicinity of the Miran Block. The refinery, which should have a capacity of 20,000 bopd, is scheduled to beoperational to design specification within approximately two years of the signing of the agreement.New projectsOver the last six months the Group has expanded its portfolio by obtaining the right to acquire a75 per cent. interest in two exploration licences in Mali, a 60 per cent. working interest in an explorationlicence in Pakistan and a 100 per cent. interest in two licences offshore to Malta. The Group has beenappointed as operator of these licences.5. RESULTS OF CONTINUING OPERATIONS FOR THE GROUP FOR THE NINE-MONTHPERIOD ENDED 30 SEPTEMBER 2006 AND 2007 PREPARED IN ACCORDANCE WITH IFRS5.1 Group ResultsThe following table sets forth the Group’s results for the nine-month periods ended 30 September 2006and 2007 prepared in accordance with IFRS.Nine-month periods ended30 September2006 2007$ $(Unaudited)RevenuePetroleum and natural gas .................................... 2,984,091 2,843,053Drilling services ............................................ 2,491,339 —5,475,430 2,843,053ExpensesPetroleum and natural gas operating ............................. 516,868 1,814,335Drilling rig operating ........................................ 1,912,123 38,360General and administrative .................................... 5,446,010 31,331,031Foreign exchange losses (gains) ................................. 449,507 (76,493)Depletion, depreciation and amortisation .......................... 948,477 1,306,131Exploration expenditure ...................................... 3,373,024 4,937,595Impairment of property, plant and equipment ...................... — 1,799,76212,646,009 41,150,721Gain on disposal of subsidiaries ................................ — 1,077,132Finance income (costs)Interest income ............................................ 985,353 1,243,305Loss 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 ProductionThe Group’s net production in bopd from continuing operations is analysed below.Nine-month periodsended 30 SeptemberAverage net production 2006 2007Bopd Bopd(Unaudited)OmanCondensate ................................................... 108 89LPG........................................................ 64 58172 147RussiaOil......................................................... — 175Total ......................................................... 172 322Net daily condensate and LPG production from the Bukha field, Block 8, Oman varied between 140 and172 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 theGroup’s share of production resulting from higher cost recoveries from the drilling of the West Bukha wellwhich spud in May 2006.Crude oil production from the Zapadno Chumpasskoye field in Russia commenced on 14 May 2007 andaveraged 362 bopd in the three months ended 30 September 2007.5.3 Petroleum and Natural Gas RevenuePetroleum and natural gas revenue may be analysed as follows.Nine-month periods ended30 September2006 2007$ $(Unaudited)OmanCondensate ................................................ 2,676,230 1,556,610LPG..................................................... 307,861 301,904RussiaOil ...................................................... — 984,5392,984,091 2,843,053Petroleum 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 ofcondensate from inventory. Condensate production from the Bukha field, Oman was sold to SumitomoCorporation 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-monthperiod ended 30 September 2007 was $984,539.There was no third party drilling revenue in the nine-month period ended 30 September 2007 comparedwith $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 operatorof Block 2 in Uganda.5.4 Operating ExpensesPetroleum 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 toproduction in Russia which commenced in May 2007.Operating expenses from drilling operations of $1,912,123 in the nine-month period ended 30 September2006, were substantially higher than for the nine-month period ended 30 September 2007 due to the largeincrease in third party drilling operations in that year. Drilling rig operating expenses in the nine-monthperiod ended 30 September 2007 were $38,360.The average operating cost per barrel sold during the period under review from the Bukha field in Omanmay be summarised as follows:Nine-month periodsended 30 September2006 2007$/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 ratherthan net production volumes.5.5 General and AdministrativeGeneral and administrative expenses increased from $5,446,010 in the nine-month period ended30 September 2006 to $31,331,031 in the same period of 2007. This increase arose principally from higherstock-based compensation expenses relating to the conditional stock options granted in December 2006under 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 thenine-month period ended 30 September 2007 were $8,271,491 as compared to $5,004,756 in the sameperiod of 2006. This increase resulted from the following factors:Growth of the Group. The Group has employed additional staff and has appraised and undertakenoperations 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; andIn 2006 the Group trained 40 officials from the Ministry of Oil of Iraq and the Ministry of NaturalResources in Portugal at a cost of $720,000. A previous training course was undertaken in 2004, whilstno 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, includingstock-based compensation of $8,957,752 (2006—nil).5.6 Depletion, Depreciation and AmortisationNine-month periods ended30 September2006 2007$ $(Unaudited)Depletion, depreciation and amortisationPetroleum and natural gas assets ................................ 541,171 593,869Drilling rig ................................................ 134,612 —Other corporate assets ........................................ 272,694 712,262Total ...................................................... 948,477 1,306,131Depletion, depreciation and amortisation expenses increased by $357,654 from $948,477 in the nine-monthperiod ended 30 September 2006 to $1,306,131 in the same period of 2007. This increase is principally dueto the higher carrying value of the Oman property, plant and equipment subject to depletion andadditional depreciation on corporate assets acquired in 2006 and the first half of 2007, offset by a reductionin depreciation of the drilling rig following a decrease in drilling activity.143

5.7 Exploration ExpenditureExploration 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 Groupand costs incurred in new territories prior to a licence being awarded. Exploration expenditure innine-month period ended 30 September 2006 principally related to costs in the KRI, whilst in the sameperiod in 2007 related mainly to the KRI and potential new ventures in Russia.5.8 Impairment of property, plant and equipmentThe carrying value of the drilling rig was written down to its estimated fair value. This resulted in animpairment write-down of $1,799,762 recognised in the income statement during the nine-month periodended 30 September 2007.5.9 Gain on Disposal of SubsidiariesThe Group recognised a gain on disposal of its subsidiaries of $1,077,132 in the first quarter of 2007. On9 March 2007, the Group disposed of its 65 per cent. equity interests in Pipelay and Naturalay Technologiesfor consideration of 605,000 common shares in SeaDragon. The fair value of the common sharesconsideration received of $2,420,000, which was based on the most recent private placement to arms-lengthparties, 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 higherthan in the same period in the previous year as a result of both average higher cash balances and higheraverage 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 ended30 September 2006, to $7,052,903 in the same period of 2007, as a result of the issuance of $60 millionunsecured convertible bonds in March 2006 and $165 million unsecured convertible bonds inFebruary 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 outstandingunsecured convertible bonds at 150 per cent. of par value for total proceeds of $82.5 million plus accruedinterest which was paid on 28 March 2007. This resulted in the recognition of a loss of $7,155,622 on theredemption, net of transaction costs, on the recorded liability and derivative liability in the nine-monthperiod 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 theconvertible bonds conversion options which is primarily due to the increase in share price, resulted in a lossof $5,483,503 in the nine-month period ended 30 September 2006 and a loss of $17,350,077 in the ninemonthperiod ended 30 September 2007.In the nine-month period ended 30 September 2007, the Group recognised an unrealised gain in the fairvalue of investment in warrants of $63,351. This relates to the Group’s holding of 1,500,000 warrants inAfren received as partial consideration from the sale of Heritage Congo in 2006.144

5.11 Discontinued OperationsThe results of operations in Congo have been classified as earnings from discontinued operations. Thefollowing table provides additional information with respect to the amounts included in the earnings fromdiscontinued operations.Period ended30 September 2006$RevenuePetroleum and natural gas ............................................ 3,805,505Other .......................................................... 679,5434,485,048ExpensesPetroleum and natural gas operating .................................... 653,344Royalties ........................................................ 570,826Depletion, depreciation and amortisation ................................. 843,5622,067,7322,417,3165.12 Net Loss for the PeriodsThe net loss in the nine-month period ended 30 September 2007 was $67,482,482, compared to $12,517,910in the same period in 2006. In the nine-month period ended 30 September 2007, the basic and diluted lossper share from continuing operations and net basic and diluted loss per share were $3.02, compared tobasic and diluted loss per share from continuing operations of $0.68 and the net basic and diluted loss of$0.57 in the same period in 2006.5.13 Capital ExpendituresThe following table sets out capital expenditures for the nine-month periods ended 30 September 2006and 2007:Nine-month periods ended30 September2006 2007$ $(Unaudited)UgandaDrilling ................................................... 5,327,637 7,814,808Seismic ................................................... — 12,720,495Other ..................................................... 1,171,610 1,543,3426,499,247 22,078,645OmanDrilling ................................................... 2,621,614 749,862Seismic ................................................... 332,192 88,897Other ..................................................... 233,115 1,982,6493,186,921 2,821,408RussiaDrilling ................................................... — 5,590,214Seismic ................................................... 1,373,001 —Other (1) ................................................... 4,338,516 8,645,0835,711,517 14,235,297145

Nine-month periods ended30 September2006 2007$ $(Unaudited)OtherUndeveloped lands ........................................... 16,892 713,068Drilling equipment ........................................... 768,139 —Other equipment ............................................ — 11,638,997Corporate ................................................. 1,437,206 119,9062,222,237 12,471,971Total from continuing operations ................................. 17,619,922 51,607,321Congo (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 wasundertaken in the nine-month period ended 30 September 2007.(i) In Uganda, work programs have been accelerated following the discovery of a new hydrocarbonsystem in the Albert Basin. This discovery includes the Kingfisher-1 discovery well in 2007, whichproduction tested from shallow horizons at rates of approximately 13,900 bopd. 3D and 2D seismicprogrammes have identified a number of targets in Blocks 3A and 1, for which multi-well drillingprogrammes are planned to commence in 2008.(ii) In Uganda, a circa 325 square km 3D seismic survey was carried out over the Kingfisher andneighbouring Pelican structures in Block 3A during the summer of 2007. Initial interpretation of the3D seismic survey confirms that the Kingfisher structure has an aerial of up to approximately45 square km.(iii) Also, a circa 530 km 2D seismic acquisition programme has just been completed in Block 3A in LakeAlbert. This most recent programme supplemented previously acquired 2D surveys and coveredpreviously 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 havebeen identified with associated amplitude anomalies.(v) In the Zapadno Chumpasskoye field in Russia, the second well of the appraisal/explorationprogramme, well P2, was drilled and cased during the summer and sidetracked to be used as aproducer in the field development project.(vi) The development of the West Bukha field in Block 8, Oman continued during the nine-month periodended 30 September of 2007.146

6. RESULTS OF CONTINUING OPERATIONS FOR THE YEARS ENDED 31 DECEMBER 2005AND 2006 PREPARED IN ACCORDANCE WITH IFRS6.1 Group ResultsThe following table sets forth the Group’s results for the years ended 31 December 2005 and 2006prepared in accordance with IFRS.Year ended Period ended31 December 12 December2005 2006$ $RevenuePetroleum and natural gas .................................... 841,766 3,938,512Drilling services ............................................ 342,359 2,895,7271,184,125 6,834,239ExpensesPetroleum and natural gas operating ............................. 465,110 723,611Drilling rig operating ........................................ 196,804 2,291,585General and administrative .................................... 5,706,396 8,628,127Foreign exchange losses ...................................... 1,170,906 627,005Depletion, depreciation and amortisation .......................... 738,630 1,351,987Exploration expenditure ...................................... 4,517,411 6,066,97712,795,257 19,689,292Finance income (costs)Interest income ............................................ 330,290 1,336,351Loss 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 ....................... — 9,200,700Earnings from discontinued operations ........................... 3,510,441 3,248,490Income from discontinued operations ............................ 3,510,441 12,449,190Net 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 gasinterests in the Congo in 2006. The results of operations in the Congo have been classified as results ofdiscontinued operations during the period under review and the related net assets classified as assets andliabilities of discontinued operation.6.2 Petroleum and Natural Gas ProductionYear ended31 DecemberAverage net production 2005 2006Bopd BopdOmanCondensate ...................................................... 69 105LPG ........................................................... 71 64140 169Average 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 thedrilling of the West Bukha well which spud in May 2006. Overall, gross field production of liquids declinedby 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 RevenuePetroleum and natural gas revenue may be analysed as follows.Year ended31 December2005 2006$ $OmanCondensate .................................................. 468,816 3,535,267LPG....................................................... 372,950 403,245Total ........................................................ 841,766 3,938,512Net 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 ofthe periodic nature of condensate sales and $888,081 from a 106 per cent. increase in the weighted averagecommodity prices. The average sales price per barrel increased from $24.51 in 2005 to $50.36 in 2006.6.4 Drilling Services RevenueThird party drilling rig revenue of $2,895,727 in 2006 was generated from the Group’s 50 per cent. share ofEagle 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 ExpensesPetroleum and natural gas operating costs increased from $465,110 in 2005 to $723,611 in line with thevolume 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$196,804 incurred in 2005 due to the large increase in third party drilling operations in that year.The average operating cost per barrel sold during the period under review from the Bukha field, Omanmay be summarised as follows.Year ended31 December2005 2006$/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 ratherthan net production volumes.6.6 General and AdministrativeGeneral and administrative expenses increased from $5,706,396 in 2005 to $8,628,127 in 2006. The increasemay be analysed as follows:In 2006 the Group trained 40 officials from the Ministry of Oil of Iraq and the Ministry of NaturalResources in Portugal at a cost of $720,000. A previous training course was undertaken in 2004, whilstno training was held in 2005; andThe Group continued to grow substantially in 2006, employing additional staff, appraising andundertaking operations in new territories. The Group’s increased level of activity during 2006 cangenerally be linked to the acquisition of the Zapadno Chumpasskoye field in Russia, preparation fordrilling in Uganda and initiatives in the KRI. Fees and expenses paid to technical members of staffand consultants increased by $1,530,000 in 2006, accounting for the majority of the remaining increaseof $2,201,731.In 2006, the Group capitalised $2,813,303 (2005—$1,332,363) of general and administrative costs relatingto exploration and development activities.148

6.7 Foreign Exchange LossesThere was a foreign exchange loss in 2006 of $627,005, primarily as a result of the strengthening of thepound sterling against the U.S. dollar, as the Group’s loan secured on the technical services office inLondon is a sterling-denominated loan. The technical services office in London is not revalued forexchange rate purposes, but acts as a natural hedge against adverse movements in exchange rates with thisloan. The majority of the Group’s business is transacted in U.S. dollars and, accordingly, the Group’sfunctional and reporting currency is U.S. dollars.6.8 Depletion, Depreciation and AmortisationYear ended31 December2005 2006$ $Depletion, depreciation and amortisationPetroleum and natural gas assets .................................. 441,355 807,424Drilling rig .................................................. — 176,013Other corporate assets .......................................... 297,275 368,550Total ........................................................ 738,630 1,351,987Depletion, 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 ExpenditureExploration expenditure increased from $4,517,411 in 2005 to $6,066,977 in 2006. This increase in costsreflected the increased activity of the Group and costs incurred in new territories prior to a licencebeing awarded.6.10 Gain on Disposal of Discontinued OperationsThe Group completed the sale of its interests in the Congo generating a one-off gain on sale of $9,200,700in 2006. All of the disposition agreements were completed in the financial year ended 2006. The gain wascalculated after taking into account all relevant costs, including disposal costs and costs in the capitalisedcost 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 bothaverage higher cash balances and higher average interest rates in 2006. Cash and cash equivalents aretypically held in interest-bearing treasury accounts. Invested cash generating this income was raised by theissue 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 substantialincrease 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 theconvertible bonds conversion options which is primarily due to the increase in share price resulted in a lossof $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 considerationfrom sale of Heritage Congo in 2006.149

6.12 Discontinued OperationsThe operations of the Kouakouala A licence and Noumbi permit in the Congo have been classified asdiscontinued operations in 2005 and 2006.Year ended 31 December2005 2006$ $RevenuePetroleum and natural gas ...................................... 5,444,936 5,116,368Interest ................................................... 41,361 —Other ..................................................... 1,013,010 645,9156,499,307 5,762,283Operating ExpensesOperating .................................................. 991,956 902,776Royalties .................................................. 816,740 767,455Foreign exchange losses ....................................... 69,623 —Depletion, depreciation and amortisation ........................... 1,110,547 843,5622,988,866 2,513,793Discontinued earnings for the year ................................. 3,510,441 3,248,490Production 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 in2005 to $3,248,490 in 2006.6.13 Net Loss for the YearNet loss totalled $28,367,755 in 2006, compared to a net loss of $8,262,225 in 2005. Net basic and dilutedloss per HOC Common Share was $(1.29) in 2006, compared to a net basic and diluted loss perHOC Common Share of ($0.38) in 2005.150

6.14 Capital ExpendituresThe following table sets out capital expenditures for the years ended 31 December 2005 and 2006:Year ended Period ended31 December 12 December2005 2006$ $UgandaDrilling ................................................... 2,466,385 11,999,638Seismic ................................................... 1,059,395 —Other .................................................... 2,123,457 1,665,2985,649,237 13,664,936OmanDrilling ................................................... — 3,209,500Seismic ................................................... — 419,942Other .................................................... 398,316 698,157398,316 4,327,599RussiaSeismic ................................................... — 1,345,524Acquisition of licence interest in 2005 and other ..................... 6,080,697 11,236,3316,080,697 12,581,855OtherUndeveloped land ........................................... – 317,786Drilling equipment ........................................... 638,613 851,351Corporate ................................................. 579,263 1,120,0761,217,876 2,289,213Total from continuing operations ................................ 13,346,126 32,863,603Congo (discontinued operations):Drilling ................................................... 1,683,333 1,785,004Seismic ................................................... — 296,898Other .................................................... 1,007,595 2,824,8522,690,928 4,906,754Total capital expenditures ...................................... 16,037,054 37,770,357The Kingfisher-1 well in Uganda was spud in August 2006. This deviated well was drilled to a total depth of3,195 metres and was completed in March 2007.Development of the Zapadno Chumpasskoye field, which was acquired in November 2005, commenced in2006 with the acquisition of a 200 km 2D seismic survey, civil works were undertaken, an operating officewas established in Nizhnevartovsk and the existing well #226 was re-entered culminating in a preliminaryfree-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 metresand tests produced a combined gross flowrate from two zones of approximately 12,750 bopd and26 MMscf/d of gas.Discontinued operations in 2005 and 2006 relate to the Group’s interests in the Congo which weredisposed 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 2004AND 2005 PREPARED IN ACCORDANCE WITH CANADIAN GAAP7.1 Group ResultsThe following table sets forth the Group’s results for the years ended 31 December 2004 and 2005prepared in accordance with Canadian GAAP.2004 2005$ $RevenuePetroleum and natural gas .................................... 5,592,721 6,286,702Interest .................................................. 560,926 371,651Other ................................................... 443,335 1,355,3696,596,982 8,013,722ExpensesOperating ................................................ 1,442,016 1,653,657Royalties ................................................. 345,656 816,740General & administrative ..................................... 2,633,667 5,249,862Interest .................................................. — 491,824Foreign exchange (gains) losses ................................ (1,488,026) 1,240,529Depletion, depreciation and accretion ............................ 633,643 1,636,008Write-down of unproved petroleum and natural gas interests ........... 934,771 724,9154,501,727 11,813,535Earnings (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 ProductionThe Group’s net production in bopd from continuing operations is analysed below.Year ended31 DecemberAverage net annual production 2004 2005Bpd BpdCongo ............................................................ 195 318OmanCondensate ...................................................... 148 69LPG ........................................................... 70 71218 140413 458Net production from the Kouakouala field in the Congo averaged 318 bopd in 2005, 63 per cent. higherthan in 2004. The increase arose from an additional producing well (KKL-401) brought into production inthe first quarter of 2005.Net production from the Bukha field, Oman declined from 218 bopd in 2004 to 140 bopd in 2005. Thisreduction was primarily due to the Government of Oman becoming entitled, during 2005, to a share ofproduction after full cost recovery was achieved. Overall, gross field production of liquids declined by6 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 RevenuePetroleum 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 47.53OmanCondensate ................................... 2,991,096 468,816 40.86 52.24LPG ........................................ 297,252 372,950 11.30 14.703,288,348 841,766 33.05 24.515,592,721 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 ratherthan net production volumes.Petroleum and natural gas revenue increased by $693,981 (12 per cent.) in 2005 to $6,286,702. $1,273,919of this increase resulted from a 25 per cent. increase in average commodity prices, offset by $579,938 froma 10 per cent. reduction in sales volumes. The average sales price per barrel increased from $33.66 in 2004to $42.22 in 2005.Revenue would have been higher in 2005, save for the periodic nature of condensate sales from the Bukhafield, Oman. In 2004, 73,207 bbls of condensate were sold, compared to 8,975 in 2005. However, a sale ofapproximately 17,500 bbls of condensate net to the Group took place in the first quarter of 2006.7.4 Other IncomeOther income in 2004 and 2005 included the Group’s share of a pipeline tariff in the Congo. Other incomein 2005 also included drilling income of $342,973 from the Group’s 50 per cent. share of Eagle Drill. In2005, 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 IncomeInterest income of $371,651 in 2005 was $189,275 (34 per cent.) lower than the previous year, as a result oflower 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. Thenote receivable was repaid in three tranches during 2004 and 2005, with the final payment received inMarch 2005.7.6 Operating ExpensesOperating expenses increased by $211,641 (15 per cent.) in 2005 to $1,653,657. Total operating costs fromthe Kouakouala and Oman operations in 2005 were similar to the previous year. The increase in 2005arose from the Group’s 50 per cent. share of Eagle Drill’s operating costs from drilling in Block 2, Uganda.7.7 General and AdministrativeGeneral and administrative expenses of $5,249,862 in 2005 were approximately double those incurred inthe previous year. During 2005, the Group grew substantially, employing additional staff, appraising andundertaking 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 ZapadnoChumpasskoye field in Russia and two memoranda of understanding entered into during the year inthe KRI.General and administrative expenses in 2005 included $930,000 of one-off costs associated with financingthe loan for the London technical services office and the establishment of the management and financeoffice in Lugano, Switzerland.Additionally, general and administrative expenses in 2005 were higher than the previous year as theyincluded costs of $625,365 from the amortisation of the fair value of stock options granted in 2005compared to $10,240 in 2004.153

In 2005, the Group capitalised $1,332,363 (2004—$441,075) of general and administrative costs relating toexploration and development activities.7.8 Finance CostsInterest 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 HOCwas debt free throughout that year.7.9 Foreign Exchange LossesThere was a foreign exchange loss of $1,240,529 in 2005, primarily as a result of the relative weakening ofthe Euro against the U.S. dollar. A $14 million note receivable (denominated in Euros) was repaid duringthe first quarter of 2005 and the funds were retained in Euro-denominated treasury deposits for part ofthis period.7.10 Depletion, Depreciation and AccretionDepletion, depreciation and accretion expenses increased by $1,002,365 to $1,636,008 in 2005. This wasprimarily as a result of a decrease in the level of proved reserves in the Kouakouala field in the Congo as at31 December 2005, which impacted on the depletion, depreciation and accretion expense in the fourthquarter of the year.The depletion calculation included future costs required to develop reserves in the amount of $625,000 in2005 compared to $3 million in 2004.7.11 Impairment of Unproved Petroleum and Natural Gas InterestsThere 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 EquipmentOn 9 June 2004, the Group sold a call option to Maurel et Prom for proceeds of $1.2 million entitling thepurchaser to acquire the Group’s overriding royalty interest in the Congo by 30 July 2004 for cash proceedsof $16.4 million, a loan note receivable equivalent to $14 million (denominated in Euros of approximatelyA11.6 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 itsinterest in the M’Boundi field or Kouilou permit before 31 December 2005. Concurrent with the exerciseof the option, the Group was required to acquire a 7 per cent. working interest in the Noumbi permit in theCongo 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 thesale of the Kouilou overriding royalty was calculated after taking into account all relevant costs. The sale ofthe overriding royalty would have changed the rate of depletion and depreciation for the Congo by morethan 20 per cent. Accordingly, the capitalised cost pools and project values of the other projects from thiscountry were taken into account when calculating the gain on sale of $26,269,113.7.13 Net Earnings (Loss) for the YearThere was a net loss of $3,799,813 in 2005, compared to net earnings of $28,364,368 in 2004. Net earningsin 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 Shareof $1.33 (basic) and $1.31 (diluted) in 2004.154

7.14 Capital ExpendituresAdditions to plant, property and equipment were $20,554,465 in 2005, compared to $37,318,136 in 2004.Capital expenditures in 2005 and 2004 may be analysed by country and category as follows:Year ended 31 December2004 2005$ $UgandaDrilling ................................................... 6,653,966 2,466,385Seismic ................................................... 4,130,388 1,059,395Other ..................................................... 1,647,725 2,123,45712,432,079 5,649,237CongoDrilling ................................................... 1,030,931 1,683,333Other ..................................................... 498,793 1,007,595Acquisition of licence interest ................................... 7,000,000 —8,529,724 2,690,928OmanOther ..................................................... 172,788 398,316172,788 398,316RussiaAcquisition of licence interest and other ........................... 871,950 6,558,966871,950 6,558,966OtherUndeveloped lands ........................................... 2,218,319 3,952,033Eagle Drill Rig refurbishment ................................... 640,812 638,613Corporate ................................................. 12,452,464 666,37215,311,595 5,257,018Total capital expenditures ...................................... 37,318,136 20,554,4658. FIXED PRICE CONTRACTS AND DERIVATIVE FINANCIAL INSTRUMENTSThe Group periodically adopts a hedging policy to mitigate certain exposure to commodity pricing risk. Noderivative instruments were entered into in the financial years ended 31 December 2004, 2005, 2006 or thenine-month period ended 30 September 2007.9. CONTRACTUAL OBLIGATIONS AND COMMITMENTSThe 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 incertain 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 ended31 December 2004, 2005, 2006 or the nine-month period ended 30 September 2007, that would adverselyimpact 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 theremaining $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 thanAfterPayments Due by Period Total 1 year 1 - 3 years 4 - 5 years 5 years$ Thousands $ Thousands $ Thousands $ Thousands $ ThousandsLong-term debt ................. 17,662 617 1,234 8,334 7,477Convertible bonds ............... 158,000 — — 158,000 —Operating leases ................ 9,642 229 458 458 8,497Other long term obligations ........ 140,000 40,000 100,000 — —Work programme obligations ....... 124,759 58,236 52,259 14,065 200Total contractual obligations ........ 450,063 99,082 153,951 180,857 16,174The Group’s net share of outstanding commitments at 31 December 2006 were estimated at:Less thanAfterPayments Due by Period Total 1 year 1 - 3 years 4 - 5 years 5 years$ Thousands $ Thousands $ Thousands $ Thousands $ ThousandsLong-term debt ................. 8,212 147 294 294 7,477Convertible bonds ............... 60,000 — — 60,000 —Operating leases ................ 9,642 229 458 458 8,497Work programme obligations ....... 16,750 10,000 4,875 1,875 —Total contractual obligations ........ 94,604 10,376 5,627 62,627 15,974The Group’s net share of outstanding commitments at 31 December 2005 were estimated at:Less thanAfterPayments Due by Period Total 1 year 1-3 years 4-5 years 5 years$ Thousands $ Thousands $ Thousands $ Thousands $ ThousandsLong-term debt ................. 7,768 248 246 246 7,028Capital lease obligations ........... — — — — —Operating leases ................ 2,659 217 434 434 1,574Purchase 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 8,602The Group’s net share of outstanding commitments at 31 December 2004 were estimated at:LessthanAfterPayments Due by Period Total 1 year 1-3 years 4-5 years 5 years$ Million $ Million $ Million $ Million $ MillionWork programme obligations .................. 7 2 3 2 —At 31 December 2004, (save for exploration work commitments included in certain of its explorationpermits) the Group did not have any material contractual obligations, lease obligations or commercialcommitments outstanding.156

10. LIQUIDITY AND CAPITAL RESOURCESThe Group’s financial strategy has been to fund its capital expenditure programme and any potentialacquisitions 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 bondsor additional HOC Common Shares.10.1 Capital ResourcesNine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRSAs 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 wereused 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 generalcorporate funding purposes.In October 2007, the Group received a loan of US$9.45 million to refinance the acquisition of a corporatejet. Interest on the loan is variable at a rate of LIBOR plus 1.6 per cent. The loan, which is secured on thecorporate jet, is scheduled to be repaid by 19 consecutive quarterly instalments of principal. Eachinstalment equals to $117,500 with the final instalment being $7,217,500. HOC provided a corporateguarantee to the lender in respect of this loan.On 14 November 2007, HOC completed an equity offering, whereby 3,000,000 HOC Common Shares wereissued 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 IFRSAs at 31 December 2006, the Group had a working capital surplus of $44,467,745.Year Ended 31 December 2005 Prepared in Accordance with IFRSAs 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 GAAPAs at 31 December 2004, the Group had a working capital surplus of $19,125,890.10.2 DebtNine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRSOn 17 January 2007, the Group gave notice that it had exercised its option to redeem the 550 outstandingunsecured convertible bonds at 150 per cent. of par value for total proceeds of $82.5 million plus accruedinterest which was paid on 28 March 2007. Fifty of the 600 unsecured convertible bonds, with a total parvalue of $5 million, were converted into 277,778 HOC Common Shares at an exercise price of $18 pershare subsequent to 31 December 2006. As a result of this conversion, a total amount of $7,104,327 wastransferred to Share Capital from convertible bonds and derivative liability component of convertiblebonds.On 16 February 2007, HOC raised $165 million gross by completing the private placement of convertiblebonds. HOC issued 1,650 unsecured convertible bonds, at par, which have a maturity of five years and oneday and an annual coupon of 8 per cent. paid semi-annually. The bonds are convertible into HOCCommon Shares at a price of $47 per share. HOC may redeem, in whole or part, the bonds for cash at anytime on or before 16 February 2008, at 150 per cent. of par value. Bondholders have a put option requiringHOC to redeem the bonds at par, plus accrued interest, in the event of a change of control of HOC orrevocation or surrender of the Zapadno Chumpasskoye licence in Russia. In the event of a change ofcontrol and redemption of the bond or exercise of the conversion rights a cash payment of up to $19,700 oneach bond will be made to the bondholder, the amount of which depends upon the date of redemption andmarket value at the date of any change of control event. Under the conditions of the HOC Bonds, HOC isrequired to take (or to procure that there is taken) all necessary action to ensure that immediately uponcompletion of the Plan of Arrangement, at its option, either (a) the Company is substituted under thebonds as principal debtor in place of HOC or becomes a guarantor under the bonds and, in either case, to157

make necessary consequential amendments such that the bonds may be converted into or exchanged forOrdinary Shares; or (b) such amendments are made to the bonds such that the bonds may be convertedinto or exchanged for Ordinary Shares. The bonds included conversion features which in certaincircumstances could be settled in cash and so these features represent a derivative financial instrumentwhich is classified as a liability. The fair value of the liability component of the bonds net of issue costs wasestimated at $140,154,215. The fair value of derivative liability representing the bondholders conversionfeature was estimated at $17,866,517 on 16 February 2007. The difference between the $165.0 million dueon maturity and the initial liability component is accreted using the effective rate method and recorded asfinance 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 received148,937 HOC Common Shares in August 2007. As a result of this conversion, a total amount of $8,944,487was transferred to share capital from convertible bonds, derivative liability component of convertible bondsand 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 corporatejet, is scheduled to be repaid by 20 consecutive quarterly instalments of principal. Each instalment equalsto $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 IFRSOn 27 March 2006, HOC issued 600 unsecured convertible bonds each with a par value of $100,000 foraggregate proceeds of $60 million. The bonds had a coupon rate of 10 per cent. per annum and a term offive years and one day. At the option of the holders, the bonds were convertible, in whole or in part, intoHOC Common Shares at a price of U.S.$18 per share at any time during the term of the bonds. HOC hadan option to redeem, in whole or part, the bonds for cash at any time on or before 28 March 2007, at150 per cent. of par value. On 17 January 2007, HOC gave notice that it had exercised its option to redeemthe 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 into277,778 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 fromconvertible bonds liability and derivative liability component of convertible bonds.Year Ended 31 December 2005 Prepared in Accordance with IFRSIn January 2005, HOC received a sterling denominated loan of £4.5 million to refinance the acquisition ofits technical services office at 34 Park Street, Mayfair, London W1K 2JD. Interest on the loan is fixed at6.515 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 atmonthly 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 GAAPThe Group had no debt during 2004.10.3 Share CapitalNine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRSDuring the nine-month period ended 30 September 2007, HOC issued 426,715 HOC Common Shares onconversion 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 IFRSDuring 2006, HOC issued 143,333 HOC Common Shares on the exercise of options.158

Year Ended 31 December 2005 Prepared in Accordance with IFRSIn 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, HOCpurchased an aggregate of 135,100 HOC Common Shares under the Normal Course Issue Bid at anaverage price of $7.85 per share, which were cancelled.Year Ended 31 December 2004 Prepared in Accordance with Canadian GAAPDuring 2004, the HOC issued 462,334 HOC Common Shares: 442,334 by the exercise of options and20,000 by the exercise of warrants.A Normal Course Issuer Bid programme commenced on 4 November 2003, expired on 3 November 2004,and was replaced by a further Normal Course Issuer Bid programme that commenced on4 November 2004 and expired on 3 November 2005. In 2004, HOC did not acquire any HOCCommon Shares.From time to time, HOC believes that the buy-back of HOC Common Shares represents an appropriateuse of funds when it is the opinion of management that the market price of HOC Common Shares is at adiscount to the fair value of the shares.During 2004, HOC’s trading symbol was changed from HOC.A to HOC. At HOC’s Annual and SpecialGeneral Meeting on 23 June 2004, shareholders approved the removal of Class ‘‘B’’ HOC Common Sharesand agreed to redesignate Class ‘‘A’’ shares as HOC Common Shares.10.4 Cash FlowsNine-Month Periods Ended 30 September 2006 and 2007 Prepared in Accordance with IFRSThe following table sets forth the Group’s cash flows for the nine-month periods ended 30 September 2006and 2007:Nine-month periods ended30 September2006 2007$ $(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 75,080,072Cash provided by discontinued operations ......................... 1,009,595 —Foreign exchange gains on cash held in foreign currency .............. 308,481 701,730Net increase in cash and cash equivalents ......................... 38,268,250 15,033,565Cash and cash equivalents at the end of the period .................. 46,851,571 61,894,711The 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 primarilydue to an increased loss from continuing operations.Net cash used in investing activities increased from $12,074,902 in the nine-month period ended30 September 2006 to $53,535,576 in the nine-month period ended 30 September 2007. Investing activitiesprincipally comprises property, plant and equipment capital expenditures.Net cash from financing activities increased to $75,080,072 in the nine-month period ended30 September 2007 primarily as a result of the issue of $165 million unsecured convertible bonds inFebruary 2007, offset by the redemption of the outstanding $55 million of the convertible bonds issued in2006 at a premium of 150 per cent. A total of $5 million of the $60 million convertible bonds issued in 2006were converted into equity prior to the issue of the redemption notice.159

Years Ended 31 December 2005 and 2006 Prepared in Accordance with IFRSThe following table sets forth the Group’s cash flows for the years ended 31 December 2005 and 2006:Year ended 31 December2005 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 58,031,186Discontinued operations ...................................... 4,313,817 21,324,969Foreign exchange gains (losses) on cash held in foreign currency ......... (1,185,123) 482,954Net increase (decrease) in cash and cash equivalents ................. (7,652,202) 38,277,825Cash and cash equivalents at the end of the year .................... 8,583,321 46,861,146Net cash outflows from continued operating activities increased from $7,854,323 in 2005 to $12,737,451 in2006 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 primarilyconsisted 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 $28,823,833 in 2006. Investingactivities principally comprises property, plant and equipment capital expenditures.Years Ended 31 December 2004 and 2005 Prepared in Accordance with Canadian GAAPYear ended 31 December2004 2005$ $Net earnings (loss) from continuing operations ..................... 28,364,368 (3,799,813)Items not involving cash ...................................... (26,498,359) 4,496,936Net cash flows from operating activities ........................... 1,866,009 697,123Net cash from financing activities ............................... 604,953 9,020,147Net 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 8,583,32111. CRITICAL ACCOUNTING POLICIES11.1 Critical IFRS accounting policies(a) Exploration and evaluation expenditureThe Group applies a modified full cost method of accounting for E&E costs, having regard to therequirements of IFRS 6 ‘Exploration for and Evaluation of Mineral Resources’. Under this method ofaccounting, costs of exploring for and evaluating petroleum and natural gas properties are capitalised on alicence or prospect basis and the resulting assets are tested for impairment by reference to appropriate costpools. Such cost pools are based on geographic areas and are not larger than a segment. The Group hadsix 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 includecosts incurred prior to having obtained the legal rights to explore an area, which are expensed directly tothe 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, theamount 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 carriedforward until the existence (or otherwise) of commercial reserves has been determined. The Group’sdefinition of commercial reserves for such purpose is proved and probable reserves on an entitlementbasis.Proved and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquidswhich 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 consideredcommercially producible. There should be a 50 per cent. statistical probability that the actual quantity ofrecoverable 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 componentof 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 developingand 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 expectedhydrocarbon production; and– evidence that the necessary production, transmission and transportation facilities are available orcan be made available.Furthermore:(i) Reserves may only be considered proved and probable if producibility is supported by eitheractual 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, orboth, and (b) the immediately adjoining portions not yet drilled, but which can be reasonablyjudged as economically productive on the basis of available geophysical, geological andengineering data. In the absence of information on fluid contacts, the lowest known structuraloccurrence of hydrocarbons controls the lower proved limit of the reservoir.(ii) Reserves which can be produced economically through application of improved recoverytechniques (such as fluid injection) are only included in the proved and probable classificationwhen successful testing by a pilot project, the operation of an installed programme in thereservoir, or other reasonable evidence (such as, experience of the same techniques on similarreservoirs or reservoir simulation studies) provides support for the engineering analysis on whichthe project or programme was based.If commercial reserves have been discovered, the related E&E assets are assessed for impairment on a costpool basis as set out below and any impairment loss is recognised in the income statement. The carryingvalue, after any impairment loss, of the relevant E&E assets is then reclassified as development andproduction assets within property, plant and equipment.E&E assets are assessed for impairment when facts and circumstances suggest that the carrying amountmay exceed its recoverable amount. Such indicators include the point at which a determination is made asto whether or not commercial reserves exist. Where the E&E assets concerned fall within the scope of anestablished full cost pool, the E&E assets are tested for impairment together with all development andproduction assets associated with that cost pool, as a single cash generating unit. The aggregate carryingvalue is compared against the expected recoverable amount of the pool, generally by reference to thepresent 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 generallybe 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 assetsThe Group had three cost pools at the development and production stage: Congo, Russia andOman during the period under review.161

Development and production assets are accumulated on a field-by-field basis and represent thecost of developing the commercial reserves discovered and bringing them into production,together with the E&E expenditures incurred in finding commercial reserves transferred fromintangible 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 ofproduction method by reference to the ratio of production in the period to the related provedplus probable reserves of the field, taking into account estimated future developmentexpenditures necessary to bring those reserves into production.An impairment test is performed whenever events and circumstances arising during thedevelopment or production phase indicate that the carrying value of a development or productionasset may exceed its recoverable amount. The aggregate carrying value is compared against theexpected recoverable amount of the cash generating unit, generally by reference to the presentvalue 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 anumber of field interests may be grouped as a single cash generating unit where the cash flowsgenerated by the fields are interdependent.(ii) Other assetsOther property, plant and equipment are stated at cost less accumulated depreciation and anyimpairment 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 drillingdays with a 20 per cent. residual value.The corporate jet is depreciated over its expected useful life of 69 months. Depreciation ischarged so as to write off the costs, less estimated residual value of the corporate jet on astraight-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) ProvisionsAsset retirement obligationsProvision is made for the estimated cost of any asset retirement obligations when the Group has a presentlegal or constructive obligation as a result of past events, it is probable that an outflow of resources will berequired to settle the obligation and the amount has been reliably estimated. Provisions are not recognisedfor future operating losses. Asset retirement obligation expense is capitalised in the relevant asset categoryunless 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 tosettle the present obligation at the balance sheet date. The discount rate used to determine the presentvalue 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 atthe end of each period to reflect the passage of time and changes in the estimated future cash flowsunderlying the obligation. The increase in the provision due to the passage of time is recognised as financecosts 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 IFRSThe Consolidated Balance Sheet as at 1 January 2005 and Consolidated Balance Sheet and ConsolidatedIncome Statement for the year ended 31 December 2005 and conversion from Canadian GAAP to IFRSThe following tables are based on information extracted from the audited financial statements at31 December 2004 and for the year ended 31 December 2005 and reconcile the Consolidated BalanceSheet 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 ofPrevious transition toNotes Canadian GAAP IFRS IFRS$ $ $AssetsNon-current assets:Intangible exploration assets ............ (b),(c) — 32,725,642 32,725,642Intangible development costs ............ 1,013,012 — 1,013,012Property, plant and equipment .......... (a),(b),(d),(g) 54,083,097 (32,306,191) 21,776,90655,096,109 419,451 55,515,560Current assetsInventories ......................... (d) 94,483 24,976 119,459Prepaid expenses .................... 272,168 — 272,168Trade and other receivables ............. 8,920,963 — 8,920,963Cash and cash equivalents .............. 16,235,523 — 16,235,52325,523,137 24,976 25,548,113Total Assets ........................ 80,619,246 444,427 81,063,673LiabilitiesCurrent liabilitiesTrade and other payables .............. 6,397,247 — 6,397,2476,397,247 — 6,397,247Non-current liabilitiesProvisions ......................... 328,553 — 328,553Total Liabilities ..................... 6,725,800 — 6,725,800Net Assets ......................... 73,893,446 444,427 74,337,873EquityShare capital ....................... 21,434,168 — 21,434,168Reserves .......................... 24,421 — 24,421Retained earnings .................... (a),(c),(d),(g) 52,434,857 444,427 52,879,284Total Equity ........................ 73,893,446 444,427 74,337,873163

(b) At 31 December 2005:Effect ofPrevious transition toNotes Canadian GAAP IFRS IFRS$ $ $AssetsNon-current assets:Intangible exploration assets ......... (b),(c),(f) — 43,503,704 43,503,704Intangible development costs ......... 1,187,371 — 1,187,371Property, plant and equipment ........ (a),(b),(d),(g) 74,729,540 (49,446,988) 25,282,55275,916,911 (5,943,284) 69,973,627Current assetsInventories ...................... (d) 216,474 35,441 251,915Prepaid expenses .................. 219,222 — 219,222Trade and other receivables .......... 1,318,450 — 1,318,450Cash and cash equivalents ........... 8,583,321 — 8,583,32110,337,467 35,441 10,372,908Total Assets ..................... 86,254,378 (5,907,843) 80,346,535LiabilitiesCurrent liabilitiesTrade and other payables ............ 4,438,649 — 4,438,649Borrowings ...................... 248,045 — 248,0454,686,694 — 4,686,694Non-current liabilitiesBorrowings ...................... 7,520,438 — 7,520,438Deferred tax liabilities .............. (f) 2,346,605 (2,346,605) —Provisions ....................... 434,849 — 434,84910,301,892 (2,346,605) 7,955,287Total Liabilities ................... 14,988,586 (2,346,605) 12,641,981(71,265,792) (3,561,238) 67,704,554EquityShare capital ..................... 22,854,418 — 22,854,418Reserves ........................ (e) 517,209 456,747 973,956Retained earnings (deficit) ........... (a),(c),(d),(e),(g) 47,894,165 (4,017,985) 43,876,180Total Equity ..................... 71,265,792 (3,561,238) 67,704,554164

(c) Reconciliation of loss for the year ended 31 December 2005:Effect ofPrevious transition toNotes Canadian GAAP IFRS IFRS$ $ $RevenuePetroleum and natural gas ................ 841,766 — 841,766Drilling services ........................ 342,359 — 342,3591,184,125 — 1,184,125ExpensesPetroleum and natural gas ................ 465,110 — 465,110Drilling rig operating .................... 196,804 — 196,804General and administrative ............... (e) 5,249,649 456,747 5,706,396Foreign exchange losses .................. 1,170,906 — 1,170,906Depletion, depreciation and amortisation ..... (c),(d),(g) 536,093 202,537 738,630Exploration expenditure .................. (a) — 4,517,411 4,517,411Impairment of unproved oil & gas interest .... (a) 724,915 (724,915) —8,343,477 4,451,780 12,795,257Interest income (costs)Interest income ........................ 330,290 — 330,290Finance 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) 3,510,441Net loss ............................. (3,799,813) (4,462,412) (8,262,225)(a) Pre-licence costsUnder Canadian GAAP, certain costs incurred prior to having obtained licence rights were included withinproperty, plant and equipment. Under IFRS, such expenditures are expensed as incurred. The impact onadoption of IFRS at 1 January 2005 is a reduction in property, plant and equipment and retained earningsof $2,162,301.As at 31 December 2005, this has resulted in a reduction in property, plant and equipment and retainedearnings of $5,954,798, an increase in exploration expenditure for the year of $4,517,411, and a decrease inthe impairment of unproved petroleum and natural gas interests recognised in the year of $724,915. Theincome tax impact was in a further reduction of property, plant and equipment of $2,346,605 and acorresponding decrease in the deferred tax liability.(b) Reclassification of exploration and evaluation costsUnder Canadian GAAP property, plant and equipment included certain exploration and evaluationexpenditure incurred within established geographic cost pools. Under IFRS, such exploration andevaluation 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 tointangible exploration of $45,111,919 (1 January 2005: $32,589,744).(c) Capitalisation of tangible asset depreciation to intangible assetsUnder IFRS, intangible exploration and evaluation costs include the depreciation of any tangible assetsutilised in incurring the costs. As these assets were classified as property, plant and equipment underCanadian 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 retainedearnings 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 impairmentUnder IFRS, impairment losses previously recorded are reversed if the conditions giving rise to theimpairment 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 inproperty, 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 equipmentof $1,442,748, retained earnings of $1,478,189, and depletion expense for the year of $203,633.(e) Share-based paymentsUnder Canadian GAAP, the Group recognised an expense related to their share-based payments on astraight-line basis through the date of full vesting. Under IFRS, the Group is required to recognise theexpense 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 sharebasedpayments reserves of $456,747, with a corresponding decrease in retained earnings.(f) Deferred taxUnder Canadian GAAP, the Corporation recognised a deferred tax liability and corresponding increase inproperty, plant and equipment associated with its acquisition of Russian properties. However, under IFRSdeferred tax is only recognised on the initial recognition of an asset if it is acquired through a businesscombination.At 31 December 2005 and 31 December 2006, this has resulted in a reduction in property, plant andequipment and deferred tax liability of $2,346,605. There was no impact at 1 January 2005.(g) Depletion policyUpon transition to IFRS, the Corporation adopted a policy of depleting petroleum and natural gasinterests on a units of production basis over proved plus probable reserves. The depletion policy underCanadian 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 andretained earnings of $789,008. At 31 December 2005, this resulted in increases in property plant andequipment and retained earnings of $743,642, and depletion expense for the year of $34,734, and adecrease in earnings from discontinued operations of $10,632. At 31 December 2006, this resulted indecreases in property plant and equipment of $233,631, retained earnings of $211,900, and earnings fromdiscontinued operations of $674,905, and increases in inventory of $21,731, and depletion expense for theyear of $280,637.12. RELATED PARTY TRANSACTIONSNine-Month Period Ended 30 September 2007 Prepared in Accordance with IFRSDuring the nine-month period ended 30 September 2007, general and administrative expenses includedadvisory fees of $806,607 ($644,258 in the nine-month period ended 30 September 2006) charged byMr. 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 acquired605,000 common shares in SeaDragon on 9 March 2007 through the sale of its 65 per cent. interest inPipelay and Naturalay Technologies.Year Ended 31 December 2006 Prepared in Accordance with IFRSIn 2006, general and administrative expenses included an advisory fee of $1,494,317 charged byMr. Anthony Buckingham, a director of HOC, who was appointed CEO on 6 October 2006.Year Ended 31 December 2005 Prepared in Accordance with IFRSIn 2005, the Group established a management and finance office in Switzerland that required Mr. AnthonyBuckingham, 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 GAAPIn 2004, general and administrative expenses included an advisory fee of $429,208 charged by Mr. AnthonyBuckingham.13. CURRENT TRADING AND PROSPECTSThe Company is well positioned to benefit from a series of exploration, appraisal and development drillingin 2008. Drilling programmes in Blocks 3A and 1 are scheduled to commence in Uganda in 2008. Anexploration well is also scheduled to commence drilling in the Miran licence in the KRI in the second halfof 2008.Production from the Zapadno Chumpasskoye field should increase from the average of 342 bopd inFebruary 2008 as a result of existing wells being brought on production as well as further developmentdrilling.Production from Block 8, Oman is not expected to change materially from the average net production of109 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 INDEBTEDNESSThe following tables show the consolidated capitalisation of the Group and the indebtedness of the Groupas at 31 December 2007.As atCapitalisation 31 December 2007(Thousands of $)Shareholders’ equityShare capital ...................................................... 217,447Reserves ......................................................... 42,867Capital and reserves ................................................ 260,314Total Capitalisation ................................................. 260,314As at31 December 2007(Thousands of $)Total current debtCurrent portion of secured long-term debt ................................ 628628Total non-current debt (excluding current portion of long-term debt)Non-current portion of secured long-term debt ............................. 17,036Convertible bonds .................................................. 137,213Derivative financial liability ........................................... 36,740190,989Total indebtedness .................................................. 191,617The following table shows the net financial indebtedness of the Group as at 31 December 2007.As at31 December 2007(Thousands of $)Cash ............................................................ 230,121Cash equivalents ................................................... —Liquidity ......................................................... 230,121Current financial indebtednessCurrent portion of long-term debt ...................................... (628)(628)Non-current financial indebtednessNon-current portion of long-term debt ................................... (17,036)Convertible bonds .................................................. (137,213)Derivative financial liability ........................................... (36,740)(190,989)Net funds ........................................................ 38,504As 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 INFORMATIONA. FINANCIAL INFORMATION RELATING TO THE COMPANYSet out on the following pages is financial information relating to the Company as at 28 March 2008prepared in accordance with International Financial Reporting Standards (IFRS).169

Accountant’s report on historical financial information of Heritage Oil LimitedKPMG LLP8 Salisbury Square,London, EC4Y 8BB,United KingdomThe DirectorsHeritage Oil LimitedOrdnance House31 Pier RoadSt. HelierJersey, JE4 8PWChannel IslandsDear SirsHeritage Oil Limited (the ‘‘Company’’)We report on the financial information set out on pages 172 to 173 in relation to the Company. Thisfinancial information has been prepared for inclusion in the prospectus that will be dated 28 March 2008 ofthe Company on the basis of the accounting policies set out in note 1. This report is required byparagraph 20.1 of Annex I of the Prospectus Directive Regulation and is given for the purpose ofcomplying with that paragraph and for no other purpose.ResponsibilitiesThe Directors of the Company are responsible for preparing the financial information on the basis ofpreparation set out in note 1 to the financial information and in accordance with International FinancialReporting 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 extentthere provided, to the fullest extent permitted by law we do not assume any responsibility and will notaccept any liability to any other person for any loss suffered by any such other person as a result of, arisingout of, or in connection with this report or our statement, required by and given solely for the purposes ofcomplying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to itsinclusion in the prospectus.Basis of opinionWe conducted our work in accordance with Standards for Investment Reporting issued by the AuditingPractices Board in the United Kingdom. Our work included an assessment of evidence relevant to theamounts and disclosures in the financial information. It also included an assessment of the significantestimates and judgments made by those responsible for the preparation of the financial information andwhether the accounting policies are appropriate to the entity’s circumstances, consistently applied andadequately disclosed.We planned and performed our work so as to obtain all the information and explanations which weconsidered necessary in order to provide us with sufficient evidence to give reasonable assurance that thefinancial information is free from material misstatement whether caused by fraud or other irregularityor error.OpinionIn our opinion, the financial information gives, for the purposes of the prospectus that will be dated28 March 2008, a true and fair view of the state of affairs of the Company as at the date stated and of itschanges in Shareholder’s equity for the period then ended in accordance with the basis of preparation setout in note 1 and in accordance with IFRS as described in note 1.170

DeclarationFor the purposes of Prospectus Rule 5.5.3R (2)(f) we are responsible for this report as part of theprospectus and declare that we have taken all reasonable care to ensure that the information contained inthis report is, to the best of our knowledge, in accordance with the facts and contains no omission likely toaffect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 ofAnnex I of the Prospectus Directive Regulation.Yours faithfully(Signed) ‘‘KPMG LLP’’KPMG LLP28 March 2008171

HERITAGE OIL LIMITEDBALANCE SHEETAs at 6 February 2008ASSETSCurrent assets:Cash and cash equivalents ................................................... 4242SHAREHOLDER’S EQUITYShare capital (note 2) ...................................................... 4242See accompanying notes to balance sheet.STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY$At beginning of the period .................................................... —Profit for the period ......................................................... —Other recognised income and expense ............................................ —Issue of share capital ........................................................ 42At end of the period ......................................................... 42$The Company has not traded since incorporation on 6 February 2008.172

HERITAGE OIL LIMITEDNOTES TO BALANCE SHEETAs at 6 February 2008Heritage 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 andreporting 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 ofthree 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 theirshares for Ordinary Shares or Exchangeable Shares of HOC on a one-for-ten basis. Exchangeable Shares of HOC have certainspecial rights including the right to direct a trustee as to how it should exercise a number (equal to the number of ExchangeableShares 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 VotingShare will have the number of votes, which may be cast at any meeting at which holders of Ordinary Shares are entitled tovote, 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 areentitled to vote will be entitled to instruct the Trustee to exercise those votes attached to the Special Voting Share for eachExchangeable Share of HOC held or to obtain a proxy from the Trustee entitling the holder to vote directly, at the relevantmeeting, 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 hasmade 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 andsimultaneously 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 CallCoto perform their obligations, if any, arising upon the liquidation, dissolution or winding up of HOC, the receipt of aRetraction Request, the exercise by Alberta CallCo of its right to purchase Exchangeable Shares that are the subject of aRetraction Request and the exercise and the exercise by Alberta CallCo of its right to purchase all Exchangeable Sharesin 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 inconnection with Exchangeable Shares to be listed and posted for trading on all stock exchanges on which outstanding OrdinaryShares are listed. The Company has also agreed not to exercise any voting rights attached to the Exchangeable Shares ownedby 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 theparties.• the Sponsor’s Agreement under which, inter alia:the Company appointed JPMorgan Cazenove Limited as sponsor in connection with the application for admission of itsOrdinary Shares to the Official List and to trading on the London Stock Exchange (the ‘‘LSE’’); the Company has agreed topay the Sponsor a management fee of £1,000,000 plus VAT on Admission; the Company has agreed to pay (together with anyrelated value added tax) certain costs, charges, fees and expenses, in connection with, or incidental to Admission; theCompany has given certain warranties and undertakings to the Sponsor and given certain indemnities to the Sponsor that aretypical of an arrangement of this nature.173

B. AUDITED (AND UNAUDITED) FINANCIAL INFORMATION RELATING TO HOCSet out on the following pages is unaudited consolidated financial information of HOC for the nine monthperiod ended and as at 30 September 2006, as prepared by management, in accordance with IFRS andaudited consolidated financial information of HOC for and as at the three years and nine-month periodended 30 September 2007 (comprising the audited financial statements for the years ended31 December 2004 and 31 December 2005 prepared in accordance with Canadian GAAP, and auditedfinancial information for the years ended and as at 31 December 2005 and 31 December 2006, and for thenine-month period ended and as at 30 September 2007 prepared in accordance with IFRS).174

AUDITED AND UNAUDITED FINANCIAL INFORMATION RELATING TO HERITAGE OILCORPORATION (HOC) PREPARED IN ACCORDANCE WITH IFRSAccountant’s report on historical consolidated financial information of Heritage Oil CorporationKPMG LLP8 Salisbury Square,London, EC4Y 8BB,United KingdomThe DirectorsHeritage Oil LimitedOrdnance House31 Pier RoadSt. HelierJersey JE4 8PW, Channel IslandsDear SirsHeritage Oil Corporation (‘‘HOC’’)We report on the financial information set out on pages 177 to 220 in relation to HOC. This financialinformation has been prepared for inclusion in the prospectus that will be dated 28 March 2008 of theCompany on the basis of the accounting policies set out in note 1. This report is required by paragraph 20.1of Annex I of the Prospectus Directive Regulation and is given for the purpose of complying with thatparagraph and for no other purpose.ResponsibilitiesThe Directors of HOC are responsible for preparing the financial information on the basis of preparationset out in note 1 to the financial information and in accordance with International Financial ReportingStandards (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 extentthere provided, to the fullest extent permitted by law we do not assume any responsibility and will notaccept any liability to any other person for any loss suffered by any such other person as a result of, arisingout of, or in connection with this report or our statement, required by and given solely for the purposes ofcomplying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to itsinclusion in the prospectus.Basis of opinionWe conducted our work in accordance with Standards for Investment Reporting issued by the AuditingPractices Board in the United Kingdom. Our work included an assessment of evidence relevant to theamounts and disclosures in the financial information. It also included an assessment of the significantestimates and judgments made by those responsible for the preparation of the financial information andwhether the accounting policies are appropriate to the entity’s circumstances, consistently applied andadequately disclosed.We planned and performed our work so as to obtain all the information and explanations which weconsidered necessary in order to provide us with sufficient evidence to give reasonable assurance that thefinancial information is free from material misstatement whether caused by fraud or other irregularityor error.OpinionIn our opinion, the financial information gives, for the purposes of the prospectus dated 28 March 2008, atrue and fair view of the state of affairs of HOC as at the dates stated and of its losses, cash flows and175

ecognised income and expense for the periods then ended in accordance with the basis of preparation setout in note 1 and in accordance with IFRS as described in note 1.DeclarationFor the purposes of Prospectus Rule 5.5.3R (2)(f) we are responsible for this report as part of theprospectus and declare that we have taken all reasonable care to ensure that the information contained inthis report is, to the best of our knowledge, in accordance with the facts and contains no omission likely toaffect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 ofAnnex I of the Prospectus Directive Regulation.Yours faithfully(Signed) ‘‘KPMG LLP’’KPMG LLP28 March 2008176

HERITAGE OIL CORPORATIONCONSOLIDATED BALANCE SHEETSASSETS31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Non-current assetsAssets held for sale (note 8) ..................... — — 16,962,091 —Intangible exploration assets (note 10) .............. 43,503,704 54,767,332 45,602,140 85,746,870Intangible 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 59,105,312Other financial assets (note 13) ................... — 914,558 — 4,200,90969,973,627 89,443,027 89,458,028 149,053,091Current assetsAssets held for sale (note 8) ..................... — — 425,412 —Inventories ................................. 251,915 98,921 211,510 79,768Prepaid expenses ............................. 219,222 531,273 515,899 340,402Trade and other receivables (note 14) .............. 1,318,450 9,839,506 664,953 6,455,303Cash and cash equivalents (note 15) ............... 8,583,321 46,861,146 46,851,571 61,894,71110,372,908 57,330,846 48,669,345 68,770,18480,346,535 146,773,873 138,127,373 217,823,275LIABILITIESCurrent liabilitiesTrade and other payables (note 16) ................ 4,438,649 12,715,381 9,396,651 15,781,606Borrowings (note 17) .......................... 248,045 147,720 140,352 160,224Liabilities of disposal group held for sale (note 8) ...... — — 807,208 —4,686,694 12,863,101 10,344,211 15,941,830Non-current liabilitiesBorrowings (note 17) .......................... 7,520,438 63,124,843 62,512,234 144,918,765Derivative financial liability (note 23) ............... — 27,997,140 8,621,068 32,810,103Provisions (note 18) ........................... 434,849 62,322 — 133,274Liabilities of disposal group held for sale (note 8) ...... — — 419,770 —7,955,287 91,184,305 71,553,072 177,862,14212,641,981 104,047,406 81,897,283 193,803,97267,704,554 42,726,467 56,230,090 24,019,303SHAREHOLDERS’ EQUITY ATTRIBUTABLE TOEQUITY HOLDERS OF THE CORPORATIONShare capital (note 19) ......................... 22,854,418 24,580,984 23,508,025 40,910,098Reserves (note 20) ........................... 973,956 2,637,058 1,363,795 35,083,262Retained 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 24,019,303177

HERITAGE OIL CORPORATIONCONSOLIDATED INCOME STATEMENTSNine-month periods endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)RevenuePetroleum and natural gas ................ 841,766 3,938,512 2,984,091 2,843,053Drilling services ........................ 342,359 2,895,727 2,491,339 —1,184,125 6,834,239 5,475,430 2,843,053ExpensesPetroleum and natural gas operating ......... 465,110 723,611 516,868 1,814,335Drilling rig operating .................... 196,804 2,291,585 1,912,123 38,360General and administrative (note 7) ......... 5,706,396 8,628,127 5,446,010 31,331,031Foreign exchange losses (gains) ............ 1,170,906 627,005 449,507 (76,493)Depletion, depreciation and amortisation ..... 738,630 1,351,987 948,477 1,306,131Exploration expenditure (note 1 e) .......... 4,517,411 6,066,977 3,373,024 4,937,595Impairment of property, plant and equipment(note 12) ........................... — — — 1,799,76212,795,257 19,689,292 12,646,009 41,150,721Gain on disposal of subsidiaries (note 9) ..... — — — 1,077,132Finance income (costs)Interest income ........................ 330,290 1,336,351 985,353 1,243,305Loss on redemption of liability component ofconvertible bonds (note 17) .............. — — — (7,155,622)Loss on derivative financial liability relating toconvertible 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 equityholders of the Corporation .............. (8,262,225) (28,367,755) (12,517,910) (67,482,482)Net loss per share from continuing operationsBasic and diluted ....................... (0.54) (1.86) (0.68) (3.02)Net earnings per share from discontinuedoperationsBasic and diluted ....................... 0.16 0.57 0.11 —Net loss per shareBasic and diluted ....................... (0.38) (1.29) (0.57) (3.02)178

HERITAGE OIL CORPORATIONCONSOLIDATED STATEMENTS OF RECOGNISED INCOME AND EXPENSENine-month periods endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Changes in the fair value of available-for-salefinancial assets ........................ — — — 168,000Exchange differences on translation of foreignoperations ........................... — (4,003) — 137,771Net income (expense) recognised directly inequity .............................. — (4,003) — 305,771Net loss for the period ................... (8,262,225) (28,367,755) (12,517,910) (67,482,482)Total recognised income and expense for theperiod .............................. (8,262,225) (28,371,758) (12,517,910) (67,176,711)179

HERITAGE OIL CORPORATIONCONSOLIDATED CASH FLOW STATEMENTSNine-month periods endedYears ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Cash provided by (used in)Operating activitiesNet loss from continuing operations for the period ..... (11,772,666) (40,816,945) (14,935,226) (67,482,482)Items not affecting cashDepletion, depreciation and amortisation .......... 738,630 1,351,987 948,477 1,306,131Finance costs—accretion expenses ............... — 647,453 453,025 1,293,845Foreign exchange losses (gains) ................. 480,253 422,648 314,022 (327,671)Share-based compensation .................... 1,082,112 1,417,044 441,254 25,055,502Loss on redemption of convertible bonds .......... — — — 7,155,622Loss on derivative financial liability .............. — 24,851,295 5,483,503 17,350,077Gain 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) 2,206,961Continuing 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 activitiesProperty, 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 activitiesShares issued for cash ......................... 1,423,011 1,318,945 602,193 198,926Convertible bonds ............................ — 60,000,000 60,000,000 165,000,000Convertible 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 14,331,835Cash and cash equivalents—Beginning of period ....... 16,235,523 8,583,321 8,583,321 46,861,146Foreign exchange (loss) gain on cash held in foreigncurrency ................................. (1,185,123) 482,954 308,481 701,730Cash and cash equivalents—End of period ........... 8,583,321 46,861,146 46,851,571 61,894,711Non-cash investing and financing activities (note 26)Supplementary informationThe following have been included within cash flows from continuing operations for theperiod under operating activitiesInterest received ........................... 397,640 1,665,998 1,235,166 2,354,886Interest paid .............................. 491,824 5,032,919 3,391,392 8,404,891180

HERITAGE OIL CORPORATIONNOTES TO CONSOLIDATED FINANCIAL INFORMATIONHeritage Oil Corporation (the ‘‘Corporation’’) is incorporated under the Business Corporations Act(Alberta) and its primary business activity is the exploration, development and production of petroleumand natural gas in Africa, Russia, South Asia and the Middle East.These consolidated financial statements include the results of the Corporation and all subsidiaries overwhich the Corporation exercises control. The subsidiaries consolidated within these financial statementsinclude 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 HoldingGesmbH (Austria), Heritage Oil & Gas (Gibraltar) Limited, TISE-Heritage Neftegaz (Russia), Begal AirLimited, 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 theCorporation’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 newlyincorporated company, Heritage Oil Limited (‘‘Heritage Jersey’’), becoming the parent company of theCorporation and its current subsidiaries. Heritage Jersey will be seeking to list its ordinary shares on theOfficial List of the United Kingdom Listing Authority and to trading on the Main Market of the LondonStock Exchange plc (the ‘‘LSE’’). The Corporation intends to delist its existing Common Shares from theToronto Stock Exchange (the ‘‘TSX’’) and obtain a listing for a new class of exchangeable shares on theTSX and the LSE. This financial information has been prepared for inclusion in the prospectus of HeritageJersey to be dated 31 March 2008. In order to meet the requirements relating to the age of financialinformation to be included in the prospectus, the financial information has been drawn up to30 September 2007 and comparative information has been provided for the period ended30 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 policiesThe principal accounting policies applied in the preparation of these consolidated financial statementsare set out below. These policies have been consistently applied to all the periods presented, unlessotherwise stated.a) Basis of preparationThe consolidated financial information has been prepared in accordance with the requirementsof the Listing Rules and in accordance with this basis of preparation. This basis of preparationdescribes how the financial information has been prepared in accordance with InternationalFinancial Reporting Standards (IFRS).These consolidated nine month financial statements of the Corporation have been prepared inaccordance with IFRS for the first time. This is the first set of financial statements which havebeen prepared by the Corporation under IFRS. The disclosures required by IFRS 1 concerningthe transition from Canadian Generally Accepted Accounting Principles (Canadian GAAP) toIFRS 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 certaincritical accounting estimates. It also requires management to exercise its judgement in theprocess of applying the Corporation’s accounting policies. The areas involving a higher degree ofjudgement or complexity, or areas where assumptions and estimates are significant to theconsolidated financial statements are disclosed in note 3.181

) ConsolidationThe consolidated financial statements incorporate the assets and liabilities of all subsidiaries ofthe Corporation as at 31 December 2005 and 2006 and 30 September 2006 and 2007 and theresults of all subsidiaries for the periods then ended.Subsidiaries are all entities (including special purpose entities) over which the Corporation hasthe power to govern the financial and operating policies so as to obtain benefits from its activitiesgenerally accompanying a shareholding of more than one half of the voting rights. The existenceand effect of potential voting rights that are currently exercisable or convertible are consideredwhen assessing whether the Corporation controls another entity. Subsidiaries are fullyconsolidated from the date on which control is transferred to the Corporation. They arede-consolidated from the date that control ceases. The Corporation together with its subsidiariesare referred to as the Group.The purchase method of accounting is used to account for the acquisition of subsidiaries by theGroup. The cost of an acquisition is measured as the fair value of the assets given, equityinstruments issued and liabilities incurred or assumed at the date of exchange, plus costs directlyattributable to the acquisition. Identifiable assets acquired and liabilities and contingent liabilitiesassumed in a business combination are measured initially at their fair values at the acquisitiondate, irrespective of the extent of any minority interest. The excess of the cost of acquisition overthe fair value of the Group’s share of the net fair value of the identifiable assets, liabilities andcontingent liabilities acquired is recorded as goodwill. If the cost of acquisition is less than the fairvalue of the net assets of the subsidiary acquired, the difference is recognised immediately in theincome statement.Inter-company transactions, balances and unrealised gains on transactions between Groupentities (the Corporation and its subsidiaries) are eliminated. For the purposes of consolidation,the accounting policies of subsidiaries have been changed where necessary to ensure consistencywith the policies adopted by the Corporation.c) Segment reportingThe Corporation’s primary segment reporting format is geographical. A geographical segment isengaged in providing products or services within a particular economic environment, that aresubject to risks and returns, that are different from those of segments operating in othereconomic environments.d) Joint VenturesThe majority of exploration, development and production activities are conducted jointly withothers under contractual arrangement and, accordingly, the Group only reflects its proportionateinterest in such assets, liabilities, revenues and expenses.e) Exploration and evaluation expenditureThe 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 ofMineral Resources’’. Under the modified full cost method of accounting, costs of exploring forand evaluating oil and gas properties are capitalised on a licence or prospect basis and theresulting assets are tested for impairment by reference to appropriate cost pools. Such cost poolsare 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 duringthe periods under review.E&E costs related to each licence/prospect are initially capitalised within ‘‘Intangible explorationassets’’. 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 anarea, 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&Easset, the amount reflecting that consumption is recorded as part of the cost of the intangibleasset.182

Intangible E&E assets related to each exploration licence/prospect are not depreciated and arecarried 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 reserveson an entitlement basis.Proven and probable reserves are the estimated quantities of crude oil, natural gas and naturalgas liquids which geological, geophysical and engineering data demonstrate with a specifieddegree of certainty (see below) to be recoverable in future years from known reservoirs and whichare considered commercially producible. There should be a 50 per cent statistical probability thatthe actual quantity of recoverable reserves will be more than the amount estimated as proven andprobable and a 50 per cent statistical probability that it will be less. The equivalent statisticalprobabilities for the proven component of proven and probable reserves are 90 per cent and10 percent, respectively.Such reserves may be considered commercially producible if management has the intention ofdeveloping 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 expectedhydrocarbon production; and– evidence that the necessary production, transmission and transportation facilities areavailable or can be made available.Furthermore:(i) Reserves may only be considered proven and probable if producibility is supported by eitheractual production or conclusive formation test. The area of reservoir considered provenincludes (a) that portion delineated by drilling and defined by gas-oil and/or oil-watercontacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, butwhich can be reasonably judged as economically productive on the basis of availablegeophysical, geological and engineering data. In the absence of information on fluidcontacts, the lowest known structural occurrence of hydrocarbons controls the lower provedlimit of the reservoir.(ii) Reserves which can be produced economically through application of improved recoverytechniques (such as fluid injection) are only included in the proven and probableclassification when successful testing by a pilot project, the operation of an installedprogramme in the reservoir, or other reasonable evidence (such as, experience of the sametechniques on similar reservoirs or reservoir simulation studies) provides support for theengineering analysis on which the project or programme was based.If commercial reserves have been discovered, the related E&E assets are assessed for impairmenton a cost pool basis as set out below and any impairment loss is recognised in the incomestatement. The carrying value, after any impairment loss, of the relevant E&E assets is thenreclassified as development and production assets within property, plant and equipment.E&E assets are assessed for impairment when facts and circumstances suggest that the carryingamount may exceed its recoverable amount. Such indicators include the point at which adetermination is made as to whether or not commercial reserves exist. Where the E&E assetsconcerned fall within the scope of an established full cost pool, the E&E assets are tested forimpairment 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 expectedrecoverable amount of the pool, generally by reference to the present value of the future net cashflows expected to be derived from production of commercial reserves. Where the E&E assets tobe tested fall outside the scope of any established cost pool, there will generally be no commercialreserves and the E&E assets concerned will be written off in full.f) Property, plant and equipmentDevelopment and production assetsThe Group had three cost pools at the development and production stage: Congo, Russia andOman during the period under review.183

Development and production assets are accumulated on a field-by-field basis and represent thecost of developing the commercial reserves discovered and bringing them into production,together with the E&E expenditures incurred in finding commercial reserves transferred fromintangible 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 ofproduction method by reference to the ratio of production in the period to the related provedplus probable reserves of the field, taking into account estimated future developmentexpenditures necessary to bring those reserves into production.An impairment test is performed whenever events and circumstances arising during thedevelopment or production phase indicate that the carrying value of a development or productionasset may exceed its recoverable amount. The aggregate carrying value is compared against theexpected recoverable amount of the cash generating unit, generally by reference to the presentvalue of the future net cash flows expected to be derived from the production of commercialreserves. 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 thecash flows generated by the fields are interdependent.Other assetsOther property, plant and equipment are stated at cost less accumulated depreciation and anyimpairment 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 drillingdays with a 20% residual value.The corporate jet is depreciated over its expected useful life of 69 months. Depreciation ischarged so as to write off the cost, less estimated residual value of corporate jet on a straight-linebasis.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 equivalentsCash and cash equivalents includes cash on hand, deposits held at call with banks, othershort-term highly liquid investments with original maturities of three months or less. Cash andcash equivalents are stated at amortised cost using the effective interest rate method.h) Trade and other receivablesTrade and other receivables are recognised initially at fair value and subsequently measured atamortised cost using the effective interest method, less provision for impairment. A provision forimpairment of trade receivables is established when there is objective evidence that the Groupwill not be able to collect all amounts due according to the original terms of the receivables.i) InventoriesInventories consist of petroleum, condensate, liquid petroleum gas and materials that arerecorded at the lower of weighted average cost and net realisable value. Cost comprises directmaterials, direct labour and those overheads that have been incurred in bringing the inventoriesto their present location and condition. Net realisable value is the estimated selling price in theordinary course of business, less applicable variable selling expenses. Provision is made forobsolete, slow-moving or defective items where appropriate.j) Intangible development costsDevelopment 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 futureeconomic benefits and its costs can be measured reliably. All other research and developmentcosts are charged to earnings in the period incurred.184

k) InvestmentsThe Group classifies its investments in the following categories: financial assets at fair valuethrough the income statement and available for sale financial assets. The classification dependson the purpose for which the investments were acquired. Management determines theclassification of its investments at initial recognition. During the period covered by these financialstatements the Group did not have any investments classified as ‘loans and receivables’ or ‘held tomaturity investments’.Financial assets at fair value through the income statementFinancial assets held for trading are carried at fair value with changes in fair value recognised inthe income statement. A financial asset is classified in this category if acquired principally for thepurpose of selling in the short term. Derivatives are classified as held for trading unless they aredesignated as hedges.Gains or losses arising from changes in the fair value of the ‘financial assets at fair value throughthe 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 assetsAvailable-for-sale financial assets, comprising principally marketable equity securities, arenon-derivatives that are either designated in this category or not classified. They are included innon-current assets unless management intends to dispose of the investment within 12 months ofthe 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 theincome statement) are recognised in equity. Upon sale of a security classified asavailable-for-sale, the cumulative gain or loss previously recognised in equity is recognised in theincome statement.The Group assesses at each balance sheet date whether there is objective evidence that afinancial asset or a group of financial assets is impaired. Measurement is assessed by reference tothe fair value of the financial asset or group of financial assets.l) Non-current assets held for sale(i) Assets held for saleNon-current assets (or disposal groups) are classified as assets held for sale and stated at thelower of their carrying amount and fair value less costs to sell if their carrying amount will berecovered 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 oramortised while they are classified as held for sale. Interest and other expenses attributable to theliabilities 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 assetsheld for sale are presented separately, as current assets, from the other assets in the balancesheet. The liabilities of a disposal group classified as held for sale are presented separately, ascurrent liabilities, from other liabilities in the balance sheet.(ii) Discontinued operationsA discontinued operation is a component of the Group that has been disposed of or is classifiedas held for sale and represents a separate major line of business or geographical area ofoperations, or is part of a single coordinated plan to dispose of such a line of business or area ofoperations, or is a subsidiary acquired exclusively with a view to resale. The earnings fromdiscontinued operations are presented separately on the face of the income statement.m) Trade and other payablesThese amounts represent liabilities for goods and services provided to the Group prior to the endof the financial period which are unpaid.185

n) BorrowingsBorrowings are initially recognised at fair value, net of transaction costs incurred. Borrowings aresubsequently measured at amortised cost. Any difference between the proceeds (net oftransaction costs) and the redemption amount is recognised in the income statement over theperiod of the borrowings using the effective interest method.Convertible bonds are separated into liability and derivative liability components (being thebondholders’ conversion option) and each component is recognised separately. On initialrecognition, the fair value of the liability component of a convertible bond is determined using amarket interest rate for an equivalent non convertible bond. This amount is recorded as a liabilityon an amortised cost basis using the effective interest method until extinguished on conversion ormaturity of the bonds. The fair value of the derivative liability component (see also 1 (q)) isdetermined 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 isdischarged, cancelled or expired. The difference between the carrying amount of a financialliability 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 incomeor costs.Borrowings are classified as current liabilities unless the Group has an unconditional right todefer settlement of the liability for at least 12 months after the balance sheet date.o) Borrowing costsBorrowing costs incurred for the construction of any qualifying asset are capitalised during theperiod 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 theweighted average interest rate applicable to the Group’s outstanding borrowings during theperiod. 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) ProvisionsAsset retirement obligationsProvision is made for the estimated cost of any asset retirement obligations when the Group has apresent legal or constructive obligation as a result of past events, it is probable that an outflow ofresources 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 iscapitalised in the relevant asset category unless it arises from the normal course of productionactivities.Provisions are measured at the present value of management’s best estimate of expenditurerequired to settle the present obligation at the balance sheet date. The discount rate used todetermine the present value reflects current market assessments of the time value of money andthe risks specific to the liability.Subsequent to the initial measurement of the asset retirement obligation, the obligation isadjusted at the end of each period to reflect the passage of time and changes in the estimatedfuture cash flows underlying the obligation. The increase in the provision due to the passage oftime is recognised as finance costs whereas increase due to changes in the estimated future cashflows are capitalised.q) Derivative financial liabilitiesDerivatives are initially recognised at fair value on the date a derivative contract is entered intoand are subsequently remeasured to their fair value at each reporting date. Changes in the fairvalue are recognised immediately in the income statement.r) Revenue recognitionRevenue from the sale of petroleum and natural gas is recorded when the significant risks andrewards of ownership of the product is transferred to the buyer. For sales of oil and gas this is186

usually when legal title passes to the external party. Interest income is recognised on a timeproportion basis using the effective interest method.Drilling services revenue relates to the provision of drilling services in respect of the drilling rig.s) Income taxesCurrent income tax is based on taxable profit for the period. Taxable profit differs from profit asreported 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 enactedor substantively enacted by the balance sheet date.Deferred income tax is provided in full, using the liability method, on temporary differencesarising between the tax bases of assets and liabilities and their carrying amounts in theconsolidated 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 toapply when the related deferred income tax asset is realised or the deferred income tax liabilityis settled.Deferred tax assets are recognised for deductible temporary differences and unused tax lossesonly if it is probable that future taxable amounts will be available to utilise those temporarydifferences and losses.Deferred tax assets and liabilities are offset when there is a legally enforceable right to offsetcurrent tax assets and liabilities and when the deferred tax balances relate to the same taxationauthority.t) Foreign currency translationItems included in the financial statements of each of the Corporation’s consolidated subsidiariesare measured using the currency of the primary economic environment in which the subsidiaryoperates (‘the functional currency’). The Corporation’s consolidated financial statements arepresented in U.S. dollars, which is the Corporation’s functional and presentation currency.Foreign currency transactions are translated into the respective functional currencies of groupentities using the exchange rates prevailing at the dates of the transactions. Foreign exchangegains and losses resulting from the settlement of such transactions and from the translation atperiod end exchange rates of monetary assets and liabilities denominated in foreign currenciesare recognised in the income statement, except when they are deferred in equity as part of or as ahedge of the net investment in a foreign operation.The results and financial position of all the Corporation’s consolidated subsidiaries (none ofwhich has a functional currency that is the currency of a hyperinflationary economy) that have afunctional currency different from the presentation currency are translated into the presentationcurrency as follows:i) assets and liabilities for each balance sheet presented are translated at the closing rate at thedate of that balance sheet;ii) income and expenses for each period are translated at average exchange rates (unless this isnot a reasonable approximation of the cumulative effect of the rates prevailing on thetransaction dates, in which case income and expenses are translated at the dates of thetransactions); andiii) all resulting exchange differences are recognised as income and expense in a separatecomponent of equity.Foreign currency loans and overdrafts are designated as and are considered to be hedges of theexchange rate exposure inherent in foreign currency net investments and, to the extent that thehedge is effective, exchange differences giving rise to changes in the carrying value of foreigncurrency loans are also recognised as income or expense directly in equity. All other exchangedifferences giving rise to changes in the carrying value of foreign currency loans and overdraftsare recognised in the income statement.When a foreign operation is sold or any borrowings hedging forming part of the net investmentare repaid, a proportionate share of the cumulative exchange differences previously recognised in187

equity are recognised in the income statement, as part of the gain or loss on sale whereapplicable.u) Share-based compensation plansThe Group applies the fair value method of accounting to all equity-classified stock-basedcompensation arrangements for both employees and non-employees. Compensation cost ofequity-classified awards to employees are measured at fair value at the grant date and recognisedover their vesting period with a corresponding increase in equity. The amount recognised as anexpense 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 fairvalue, and periodically remeasured to fair value until the non-employees’ performance iscomplete, and recognised over their vesting period with a corresponding increase to contributedsurplus. Upon the exercise of the award, consideration received is recognised in equity.v) Share capitalCommon Shares are classified as share capital. Incremental costs directly attributable to the issueof 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 theassociated shares are cancelled.w) Earnings per shareBasic earnings per share is calculated by dividing the profit attributable to equity holders of theCorporation by the weighted average number of Common Shares outstanding during thefinancial period.Diluted earnings per share adjusts the figures used in the determination of basic earnings pershare to take into account the after income tax effect of interest and other financing costsassociated with dilutive potential Common Shares and the weighted average number of sharesassumed to have been issued for no consideration in relation to dilutive potentialCommon Shares.The if-converted method used in the calculation of diluted earnings per share assumes theconversion of convertible securities at the later of the beginning of the reported period orissuance date, if dilutive.x) New accounting standards and interpretationsCertain new accounting standards and interpretations have been published that are notmandatory for the 30 September 2007 reporting period. The Corporation’s assessment of theimpact 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 alignssegment reporting with the requirements of the US standard SFAS 131, ‘‘Disclosures aboutsegments of an enterprise and related information’’. The new standard requires a‘‘management approach’’, under which segment information is presented on the same basisas that used for internal reporting purposes. The expected impact is still being assessed bymanagement, 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 financialstatements:i) IAS 23 (Amendment), ‘‘Borrowing costs’’ (effective from 1 January 2009), requires theGroup to capitalise borrowing costs directly attributable to the acquisition, construction orproduction of a qualifying asset (one that takes a substantial period of time to get ready foruse or sale) as part of the cost of that asset. The Group currently applies the capitalisationapproach to borrowing costs.ii) IFRIC 11, ‘‘IFRS 2—Group and treasury share transactions’’ (effective from 1 January2008), provides guidance on whether share-based transactions involving treasury shares orinvolving group entities (for example, options over a parent’s shares) should be accountedfor as equity-settled or cash-settled share-based payment transactions in the stand-aloneaccounts of the parent and group companies.188

iii) IFRIC 12, ‘‘Service concession arrangements’’ (effective from 1 January 2008), applies tocontractual 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 wheregoods or services are sold together with a customer loyalty incentive (for example, loyaltypoints or free products), the arrangement is a multiple-element arrangement and theconsideration receivable from the customer is allocated between the components of thearrangement using fair values.v) IFRIC 14, ‘‘IAS 19—The limit on a defined benefit asset, minimum funding requirementsand their interaction’’ (effective from 1 January 2008), provides guidance on assessing thelimit in IAS 19 on the amount of the surplus that can be recognised as an asset. It alsoexplains how the pension asset or liability may be affected by a statutory or contractualminimum funding requirement.The following amendments have been published, but have not been applied in these financialstatements: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 commencingon or after 1 July 2009;iii) IAS 1 (Amendment), Presentation of Financial Statements: effective for accounting periodscommencing on or after 1 January 2009;iv) IAS 23 (Amendment), Borrowing Costs: effective for accounting periods commencing on orafter 1 January 2009;v) IAS 27 (Amendment), Consolidated and Separate Financial Statements: effective foraccounting periods commencing on or after 1 July 2009.The Directors do not anticipate that the adoption of these amendments will have a materialimpact on the Group’s financial statements in the period of initial application.2 Risk managementThe 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 programmefocuses on the unpredictability of financial markets and seeks to minimise potential adverse effects onthe Group’s financial performance.a) Financial risk managementi) Foreign exchange riskForeign exchange risk arises when transactions and recognised assets and liabilities of theGroup entity concerned are denominated in a currency that is not the Corporation’sfunctional currency. The Group operates internationally and is exposed to foreign exchangerisk 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% againstthe 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—$125,982; 31 December2005—$(20,937)) higher/(lower), mainly as a result of foreign exchange gains/losses ontranslation of Canadian dollar-denominated general and administrative expenses and cash inbank. Profit is more/less sensitive to movement of Canadian/U.S. dollar exchange rates in2007 than 2006 because of significantly higher general and administrative expenses in 2007 incomparison with 2006.At 30 September 2007, if the Russian rouble had strengthened/weakened by 10% against theUS dollar with all other variables held constant, the loss for the period would have been189

$(106,943) (30 September 2006—$(53,228); 31 December 2006—$(236,730); 31 December2005—$(139)) higher/(lower), mainly as a result of foreign exchange gains/losses ontranslation 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 wouldhave been $781,534 (30 September 2006—$749,534; 31 December 2006—$730,637;31 December 2005—$686,923) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of GBP pound sterling-denominated long-term loan.At 30 September 2007, if the Swiss franc had strengthened/weakened by 10% against theUS dollar with all other variables held constant, the loss for the period would have been$(432,727) (30 September 2006—$(294,544); 31 December 2006—$(286,493);31 December 2005—$(117,816)) higher/(lower), mainly as a result of foreign exchange gains/losses on translation of Swiss franc-denominated cash in bank.ii) Commodity price riskThe Corporation is exposed to commodity price risk to the extent that it will sell itsentitlement to petroleum, condensate and liquid petroleum gas production on a floatingprice basis.The Corporation may consider partly mitigating this risk in the future.The table below summarises the impact of increases/decreases of the relevant oil /condensate / LPG benchmark on the Corporation’s post-tax profit or loss for the period andon equity. The analysis is based on the assumption that the commodity prices had increased /decreased by 5% with all other variables held constant:Year ended Nine-month periods31 December ended 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Brent light crude ...................... — — — 49,227Condensate .......................... 42,088 196,926 133,812 77,831LPG ............................... 17,118 144,786 15,393 15,09559,206 341,712 149,205 142,153Post-tax profit for the year and equity would increase/decrease as a result of commodityrevenues received.iii) Interest rate riskThe Group had fixed rate long-term debt and fixed rate convertible bonds in the periodunder review, therefore it was not exposed to interest rate risk.iv) Credit riskAll of the Corporation’s production is derived from the Republic of Congo, Russia andOman. 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 singlecustomer for each commodity. Accordingly, substantially all the Corporation’s accountsreceivables from petroleum and natural gas sales were from a maximum of four customersduring these periods.Debtors of the Corporation are subject to internal credit review to minimize the risk ofnon-payment. The Corporation does not anticipate any default as it transacts withcreditworthy counterparties.No credit limits were exceeded during the reporting periods and management does notexpect any losses from non-performance by these counterparties.190

v) Liquidity riskLiquidity risk is the risk that the Group will not have sufficient funds to meet liabilities. Cashforecasts identifying liquidity requirements of the Group are produced quarterly. These arereviewed regularly to ensure sufficient funds exist to finance the Corporation’s currentoperational and investment cash flow requirements.Management monitors rolling forecasts of the Corporation’s liquidity reserve on the basis ofexpected cash flow.The Group had available cash at approximately $62 million at 30 September 2007. Since thenit has raised approximately $186 million by way of an equity offering of Common Shares (seenote 27). Based on its current plans and knowledge, its projected capital expenditure andoperating cash requirements, the Group projects available cash at 31 December 2008 ofapproximately $122 million.The Corporation’s financial liabilities consist of trade and other payables and borrowings.Trade and other payables are due within 12 months, and borrowings fall due as outlined innote 25.b) Capital risk managementThe Corporation’s objectives when managing capital are to safeguard the Corporation’s ability tocontinue as a going concern in order to provide returns for shareholders and benefits for otherstakeholders and to maintain an optimal capital structure to reduce the cost of capital.The Corporation monitors capital on the basis of the gearing ratio. This ratio is calculated as netdebt divided by total capital. Net debt is calculated as total borrowings (including ‘borrowings’and ‘trade and other payables’ as shown in the consolidated balance sheet) less cash and cashequivalents. Total capital is calculated as ‘equity’ as shown in the consolidated balance sheet plusnet debt.As at 31 DecemberAs at 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Total borrowings ................. 12,641,981 104,047,406 81,897,283 193,803,972Less 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 35,045,712 131,909,261Total equity .................... 67,704,554 42,726,467 56,230,090 24,019,303Total capital .................... 71,763,214 99,912,727 91,275,802 155,928,564Gearing ratio ................... 6% 57% 38% 85%This increase in the gearing ratio during 2006 and 2007 resulted primarily from the issuances ofbonds and long-term debt (note 17).191

3 Critical accounting estimates, assumptions and judgementsIn 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 accountingestimates will, by definition, seldom equal the related actual results. The estimates and assumptionsthat have a significant risk of causing a material adjustment to the carrying amounts of assets andliabilities within the next financial year are discussed below:a) Recoverability of exploration and evaluation costsUnder the modified full cost method of accounting for E&E costs, certain costs are capitalised asintangible assets by reference to appropriate cost pools, and are assessed for impairment whencircumstances 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 duringthe 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 thespecific area is neither budgeted nor planned;iii) exploration for and evaluation of mineral resources in the specific area have not led to thediscovery of commercially viable quantities of mineral resources and the entity has decidedto discontinue such activities in the specific area; andiv) sufficient data exist to indicate that, although a development in the specific area is likely toproceed, the carrying amount of the exploration and evaluation asset is unlikely to berecovered in full from successful development or by sale.This assessment involves judgement as to (i) the likely future commerciality of the asset and whensuch commerciality should be determined, and (ii) future revenues and costs pertaining to anywider cost pool with which the asset in question is associated, and (iii) the discount rate to beapplied to such revenues and costs for the purpose of deriving a recoverable value. Note 10discloses the carrying amounts of the Group’s E&E assets. Consequently, major uncertaintiesaffect the recoverability of these costs which is dependent on the Group achieving commercialproduction or the sale of the assets.b) Reserve estimatesEstimates of recoverable quantities of proven and probable reserves include assumptionsregarding commodity prices, exchange rates, discount rates, production and transportation costsfor future cash flows. It also requires interpretation of complex and difficult geological andgeophysical models in order to make an assessment of the size, shape, depth, and quality ofreservoirs and their anticipated recoveries. The economic, geological and technical factors usedto estimate reserves may change from period to period. Changes in reported reserves can impactasset carrying values and the asset retirement obligation due to changes in expected future cashflows. Reserves are integral to the amount of depletion charged to the income statement and thecalculation of inventory.The level of estimated commercial reserves is also a key determinant in assessing whether thecarrying value of any of the Group’s development and production assets has been impaired.c) Fair value of financial instrumentsThe Group’s accounting policies and disclosures require the determination of the fair value offinancial instruments. Fair values have been determined for measurement and/or disclosurepurposes based on the following methods:i) Non-derivative financial instrumentsThese comprise investments in equity and debt securities, trade and other receivables, cash andcash equivalents, loans and borrowings and trade and other payables. Non-derivative financialinstruments are recognised initially at fair value plus, for instruments not at fair value throughprofit 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) DerivativesDerivatives are recognised initially at fair value; attributable transaction costs are recognised inthe profit or loss when incurred. Subsequent to initial recognition, derivatives are measured atfair value. Embedded derivatives are separated from the host contract and accounted forseparately if the economic characteristics and risks of the host contract and the embeddedderivative are not closely related, a separate instrument with the same terms as the embeddedderivative would meet the definition of a derivative, and the combined instrument is notmeasured at fair value through the income statement.The fair value of derivative financial instruments is based on their listed market prices, ifavailable. If a listed market price is not available, then fair value is estimated by discounting thedifference between the contractual forward price and the current forward price for the residualmaturity of the contract using a risk-free interest rate (based on government bonds).iii) Compound financial instrumentsCompound financial instruments issued by the Group comprise convertible bonds that can beconverted to share capital at the option of the holder, and the number of shares to be issued doesnot vary with changes in their fair value.The convertible bonds are separated into liability and derivative liability components (being thebondholders’ conversion option). The liability component of a compound financial instrument isrecognised initially at fair value, determined by reference to market interest rates for equivalentbonds which do not contain conversion features. Subsequent to initial recognition, the liabilitycomponent is measured at amortised cost using the effective interest method. The fair value ofthe derivative liability component is determined using a Black-Scholes option-pricing model andthis amount is recorded as a liability. The Black-Scholes model contains assumptions anddeterminations pertaining to volatility, risk-free interest rates, and the terms of the options.4 Segment informationThe Group has a single class of business which is international exploration, development andproduction 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 2005Depreciation,External Segment Total Capital depletion andrevenue 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 47,247 387,764 441,355Uganda (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 1,110,547Iraq ............. — (1,948,967) — — — —Pakistan .......... — (391,145) — — — —Unallocated—Corporate ....... 330,290 (8,999,396) 25,110,159 11,732,241 694,900 297,2758,013,722 (8,262,225) 80,346,535 12,641,981 16,116,635 1,849,177193

Year ended 31 December 2006Depreciation,External Segment Total Capital depletion andrevenue result Total assets liabilities additions amortisation$ $ $ $ $ $Russia ........... — (3,698) 23,395,149 150,324 12,830,190 —Oman ........... 3,938,512 716,322 10,439,341 642,607 5,226,268 807,424Uganda (1) ........ 2,895,727 428,129 46,537,931 7,311,956 14,934,054 176,013DRC............ — (51,552) 35,468 — 35,468 —Congo (2) ......... 5,762,283 12,449,190 5,157,646 — 2,610,699 843,562Iraq (3) ........... — (3,556,202) — — — —Pakistan ......... — (715,776) — — — —Unallocated—Corporate ...... 1,336,351 (37,634,168) 61,208,338 95,942,519 1,510,919 368,55013,932,873 (28,367,755) 146,773,873 104,047,406 37,147,598 2,195,549Nine-month period ended 30 September 2006 (Unaudited)Depreciation,External Segment Total Capital depletion andrevenue result Total assets liabilities additions amortisation$ $ $ $ $ $Russia ......... — — 12,767,641 44,809 5,755,031 —Oman ......... 2,984,091 1,926,052 8,757,988 589,060 4,052,188 541,171Uganda (1) ...... 2,491,339 444,604 39,225,922 4,916,993 7,312,675 134,612DRC.......... — (51,552) 26,116 — 16,893 —Congo (2) ....... 4,485,048 2,417,316 17,387,503 1,226,978 2,610,699 843,562Iraq (3) ......... — (2,836,603) — — — —Pakistan ........ — (436,818) — — — —Unallocated—Corporate .... 985,353 (13,980,909) 59,962,203 75,119,443 1,361,964 272,69410,945,831 (12,517,910) 138,127,373 81,897,283 21,109,450 1,792,039Nine-month period ended 30 September 2007Depreciation,External Segment Total Capital depletion andrevenue result Total assets liabilities additions amortisation$ $ $ $ $ $Russia ........... 984,539 (2,123,116) 38,406,629 1,010,028 15,589,608 317,688Oman ............ 1,858,514 1,100,193 12,934,518 317,249 3,597,498 276,181Uganda (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 11,758,850 712,2624,086,358 (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 notreceived 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 inaccordance with IFRS 6.194

5 Other finance costsNine-month periods endedYear ended 31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Interest on long-term debt .................. 491,824 532,918 391,392 419,898Interest on convertible bonds ................ — 4,602,740 3,090,411 9,387,986Accretion of convertible debt ................ — 860,895 578,029 2,652,613Accretion of asset retirement obligation ........ — — — 5,376491,824 5,996,553 4,059,832 12,465,873Amount capitalised ....................... — (1,354,427) (793,335) (5,412,970)Finance costs expensed .................... 491,824 4,642,126 3,266,497 7,052,903Finance costs are capitalised in various balance sheet categories.6 Income tax expenseThe Group is subject to income taxes in Canada, Uganda and Russia. All of the Group’s operatingactivities are outside of Canada. In Oman, the effective tax rate is nil as in this jurisdiction the Groupis 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), ofwhich $23,452,398 expires from 2008 to 2027, and the remaining $46,834,304 does not have an expiryperiod. No deferred tax assets have been recognised for the benefit of the Canadian tax deductionsand Canadian and Russian tax losses because realisation of the deferred tax assets in the foreseeablefuture is not sufficiently likely.Factors affecting current tax charge for the period:Nine-month periods endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Net loss on ordinary activities before tax . . . (8,262,225) (28,367,755) (12,517,910) (67,482,482)Standard tax rate .................... 37.6% 34.7% 34.7% 32.3%Tax on loss at standard rate ............. (3,108,249) (9,843,611) (4,343,715) (21,796,842)Expenses not deductible for tax purposes . . . 2,878,891 10,247,124 5,218,809 20,156,056Effect of tax losses not recognised ........ 229,358 (403,513) (875,094) 1,640,786Current tax charge ................... — — — —As at 31 DecemberAs at 30 September2005 2006 2006 2007$ $ $ $(Unaudited)The balance comprises temporary differencesattributable to:Available tax losses and deductions ....... 19,107,122 19,744,609 19,273,028 23,639,376Deferred tax asset (unrecognised) .......... 19,107,122 19,744,609 19,273,028 23,639,376195

7 Staff costsThe average number of employees (including executive directors) employed by the Group during theperiod, analysed by category was:Nine-month periodsYear endedended31 December 30 September2005 2006 2006 2007(Unaudited)Canada .................................... — — — 1Switzerland ................................. 2 3 4 3Russia .................................... — 25 25 41United Kingdom ............................. 10 13 13 14Uganda ................................... 7 21 21 21Kurdistan region of Iraq ....................... 6 7 7 5South Africa ................................ 3 3 3 4Total ...................................... 28 72 73 89The aggregate payroll expenses of those employees was as follows:Nine-month periods endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Salaries and other short-term benefits ........ 5,299,861 9,726,603 5,253,099 6,481,888Share-based compensation ................ 898,121 1,765,681 441,254 31,129,696Total employee remuneration .............. 6,197,982 11,492,284 5,694,353 37,611,584Capitalised portion of total remuneration ...... 1,755,893 4,211,166 1,459,838 10,890,269Key management compensation was:Nine-month periods endedYear ended 31 December30 September2005 2006 2006 2007$ $ $ $(Unaudited)Salaries and other short-term benefits ......... 4,237,786 4,111,948 3,213,987 3,093,756Share-based payments .................... 781,114 753,174 333,810 22,556,8425,018,900 4,865,122 3,547,797 25,650,5988 Discontinued operationsOn 6 June, 2006, the Group entered into an agreement to sell Heritage Congo Limited which held allof the Group’s interests in the Noumbi Exploration Permit and the Kouakouala A and B licences inthe Republic of Congo (‘‘Congo’’) to Afren PLC, subject to a number of conditions precedent andpre-emption rights. During 2006, the Group’s partners in the Kouakouala A and B licences exercisedtheir pre-emption rights in respect of the sale of these assets. Accordingly, the Group sold these assetsto 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 followingconsideration:a) Cash of $21,000,000; andb) 1,500,000 Afren warrants, with a term of five years and an exercise price of £0.60 per share. Thefair value of the Afren warrants, determined by using the Black-Scholes model, was $719,380 atthe 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 in196

Congo to the other partners in the licences, Maurel et Prom and Burren Energy, for the followingconsideration:a) Cash of $6,052,515; andb) An overriding royalty of 15% over a 30% working interest in the Kouakouala B licence in relationto 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 ofthe Group’s interests in the Congo was $9,200,700 in 2006. As at 31 December 2006, accountsreceivable included $5,157,646 relating to the unpaid portion of the sales proceeds, which was receivedin January 2007.The results of operations in Congo have been classified as earnings from discontinued operations. Thefollowing table provides additional information with respect to the amounts included in the earningsfrom discontinued operations.Year ended Period ended Period ended31 December 12 December 30 September2005 2006 2006$ $ $(Unaudited)RevenuePetroleum and natural gas ........................ 5,444,936 5,116,368 3,805,505Interest ...................................... 41,361 — —Other ....................................... 1,013,010 645,915 679,5436,499,307 5,762,283 4,485,048ExpensesOperating .................................... 991,956 902,776 653,344Royalties ..................................... 816,740 767,455 570,826Foreign exchange losses .......................... 69,623 — —Depletion, depreciation and accretion ................ 1,110,547 843,562 843,5622,988,866 2,513,793 2,067,7323,510,441 3,248,490 2,417,316The following table provides additional information with respect to the amounts included in thebalance sheet as assets of the disposal group held for sale.12 December 30 September2006 2006$ $(Unaudited)AssetsNon-current assetsIntangible exploration assets (note 10) ......................... 8,323,966 8,323,966Property, plant and equipment (note 12) ....................... 11,638,420 8,638,12519,962,386 16,962,091CurrentTrade and other receivables ................................. — 375,651Inventories ............................................. — 49,761— 425,41219,962,386 17,387,503LiabilitiesCurrent liabilitiesTrade and other payables ................................... 971,421 807,208Non-currentProvisions (note 18) ...................................... 419,770 419,7701,391,191 1,226,978Net assets .............................................. 18,571,195 16,160,525197

The gain on disposal of discontinued operations has been derived as follows:31 December2006$Consideration received or receivableCash ......................................................... 27,052,515Warrants ...................................................... 719,380Total disposal consideration .......................................... 27,771,895Less carrying amount of net assets sold .................................. (18,571,195)Gain on disposal .................................................. 9,200,7009 DisposalsOn 9 March 2007, the Group disposed of its previously consolidated 65% interests in Natural PipelayWorldwide Limited (‘‘NPWL’’) and Naturalay Technologies Limited (‘‘Naturalay’’) in considerationfor 605,000 common shares in a private company named SeaDragon. The fair value of the commonshares consideration received of $2,420,000, which was based on the most recent private placement bySeaDragon in October 2006, resulted in a gain of $1,077,132 on the disposal. The Group’s CFO is adirector and CFO of SeaDragon.Below is an analysis of the assets and liabilities of NPWL and Naturalay as at 9 March 2007, the dateof sale completion:AssetsIntangible development costs ........................................... 1,642,868LiabilitiesTrade and other payables ............................................. 300,000Net assets ........................................................ 1,342,868$The gain on disposal of the previously consolidated subsidiary has been derived as follows:$Consideration received or receivableFair value of shares ................................................ 2,420,000Total disposal consideration ............................................ 2,420,000Less: carrying amount of net assets sold ................................... 1,342,868Gain on disposal of subsidiaries ......................................... 1,077,13210 Intangible exploration assets31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Balance—Beginning of period ............. 32,725,642 43,503,704 43,503,704 54,767,332Exchange differences ................... — 64,121 36,270 117,189Additions ........................... 10,778,062 20,656,473 11,519,132 40,355,455Assets transferred to property, plant andequipment (note 12) .................. — (1,133,000) (1,133,000) (9,493,106)Assets transferred to disposal group held forsale (note 8) ........................ — (8,323,966) (8,323,966) —Balance — End of period ................ 43,503,704 54,767,332 45,602,140 85,746,870198

No assets have been pledged as security.The balances at the end of the periods are as follows:31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Russia .............................. 4,612,321 6,437,022 5,979,541 14,066,855Oman .............................. 3,875,880 7,048,524 5,897,554 552,257Uganda ............................. 27,163,615 41,246,318 33,708,152 69,563,207DRC............................... — 35,468 16,893 689,696Congo .............................. 7,851,888 — — —Pakistan ............................ — — — 874,855Balance — End of period ................ 43,503,704 54,767,332 45,602,140 85,746,87011 Intangible development costs31 December 30 September2005 2006 2006 2007$ $ $ $(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 1,574,039Additions—Internal development ............. 174,359 386,668 159,487 68,829Disposals—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 thedevelopment of the Buoyant Drum Lay System (‘‘Pipelay System’’). As the Pipelay Systemdevelopment was not complete, amortisation had not yet commenced before the disposal of thesubsidiaries.199

12 Property, plant and equipment31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Petroleum and natural gas interests .......... 13,255,901 18,091,216 11,349,845 36,328,564Drilling equipment ...................... 2,693,618 3,544,969 3,461,756 3,544,969Land and building ..................... 11,984,701 11,984,701 11,984,701 11,984,701Other ............................... 1,176,671 2,687,590 2,538,635 14,446,440Property, plant and equipment, at cost ...... 29,110,891 36,308,476 29,334,937 66,304,674Accumulated 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 59,105,312Reconciliation of movements during the periodPetroleum and natural gas interestsCost—Beginning of period ............... 9,250,840 13,255,901 13,255,901 18,091,216Accumulated 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 15,039,250Net book value—Beginning of period ....... 7,447,172 9,952,411 9,952,411 15,039,250Exchange differences ................... — 103,065 30,333 136,216Additions ........................... 4,005,061 14,128,855 7,460,216 8,608,026Assets transferred from intangible exploration(note 10) .......................... — 1,133,000 1,133,000 9,493,106Assets 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 32,710,637Cost—End of period ................... 13,255,901 18,091,216 11,349,845 36,328,564Accumulated depletion and depreciation—Endof 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 32,710,637Drilling and barge equipmentCost—Beginning of period ............... 2,055,006 2,693,618 2,693,618 3,544,969Accumulated 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 3,197,228Net book amount—Beginning of period ..... 1,919,108 2,521,890 2,521,890 3,197,228Additions ........................... 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 1,397,466Cost—End of period ................... 2,693,618 3,544,969 3,461,756 3,544,969Accumulated depletion and depreciation—Endof 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 1,397,466200

31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Land and buildingCost—Beginning of period ............... 11,984,701 11,984,701 11,984,701 11,984,701Accumulated 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 11,671,550Net book amount—Beginning of period ..... 11,949,906 11,810,728 11,810,728 11,671,550Depletion 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 11,567,167Cost—End of period ................... 11,984,701 11,984,701 11,984,701 11,984,701Accumulated depletion and depreciation—Endof period .......................... (173,973) (313,151) (278,357) (417,534)Net book amount—End of period .......... 11,810,728 11,671,550 11,706,344 11,567,167OtherCost—Beginning of period ............... 481,771 1,176,671 1,176,671 2,687,590Accumulated 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 2,279,070Net book amount—Beginning of period ..... 460,720 997,523 997,523 2,279,070Additions ........................... 694,900 1,510,919 1,361,964 11,758,850Depletion and depreciation ............... (158,097) (229,372) (168,310) (607,878)Net book amount—End of period .......... 997,523 2,279,070 2,191,177 13,430,042Cost—End of period ................... 1,176,671 2,687,590 2,538,635 14,446,440Accumulated depletion and depreciation—Endof period .......................... (179,148) (408,520) (347,458) (1,016,398)Net book amount—End of period .......... 997,523 2,279,070 2,191,177 13,430,042The corporate office which represents the land and building category serves as security for a long-termloan (note 17).The carrying value of the drilling rig was written down to its estimated fair value based on third-partquoted sales prices. This resulted in an impairment write-down of $1,799,762 recognised in the incomestatement during the nine-month period ended 30 September 2007.13 Other financial assets31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Investment in warrants .......................... — 914,558 — 977,909Investment in unlisted securities ................... — — — 3,223,000— 914,558 — 4,200,909The investment in Afren warrants (note 8) is classified as held for trading. The investment in unlistedsecurities represents common shares in a private company named SeaDragon (note 9), which isclassified as available-for-sale.There were no other disposals (see note 9) or impairment losses on held for trading oravailable-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 ofSeaDragon on 26 October 2006. The Directors consider that there has been no change in the fairvalue of these shares since this date.14 Trade and other receivables31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Trade receivables ......................... 879,163 890,662 152,526 551,270Other receivables ......................... 439,287 8,948,844 512,427 5,904,0331,318,450 9,839,506 664,953 6,455,303Trade and other receivables are due within 30 days from the invoice date. No interest is charged onthe 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—$1,318,450) were neither past due nor impaired.These relate to a number of independent customers for whom there is no recent history of default.The ageing analysis of these trade and other receivables is as follows:31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Up to 3 months .......................... 1,318,450 9,703,000 656,204 5,118,5973 to 6 months ........................... — 136,506 8,749 1,336,7061,318,450 9,839,506 664,953 6,455,303Trade and other receivables analysed by category are as follows:31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)U.S. dollars ............................. 1,230,410 7,970,228 253,883 5,148,165GBP pounds sterling ...................... — 24,040 — 24,040Russian roubles .......................... — 1,495,891 286,096 821,128Swiss francs ............................. 88,040 349,347 124,974 461,9701,318,450 9,839,506 664,953 6,455,30315 Cash and cash equivalents31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Cash at bank and in hand ................ 8,583,321 46,861,146 46,851,571 61,894,711Cash at bank and in hand includes cash held in interest bearing accounts.202

16 Trade and other payables31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Trade payables ......................... 1,995,384 9,253,320 6,929,625 10,669,952Other payables and accrued liabilities ........ 2,443,265 3,462,061 2,467,026 5,111,6544,438,649 12,715,381 9,396,651 15,781,606Trade and other payables and accrued liabilities comprise current amounts outstanding for tradepurchases and ongoing costs. The carrying amount of trade and other payables approximates theirfair value.17 Borrowings31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Non-current borrowingsConvertible bonds—unsecured ............ — 54,715,050 54,440,464 136,264,249Non-current portion of long-term debt ...... 7,520,438 8,409,793 8,071,770 8,654,5167,520,438 63,124,843 62,512,234 144,918,765Long-term debt—securedCurrent ............................. 248,045 147,720 140,352 160,224Non-current .......................... 7,520,438 8,409,793 8,071,770 8,654,5167,768,483 8,557,513 8,212,122 8,814,7402006 convertible bondsOn 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 netproceeds of $57,000,000. The bonds bear a coupon rate of 10% per annum and a term of five yearsand 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 shareat any time during the term of the bonds. The Corporation could redeem, in whole or part, the bondsfor cash at any time on or before 28 March 2007 at 150 per cent. of par value. Pursuant to the bondagreement, the Group is required to maintain an equity to debt, net of cash and cash equivalent, ratioof no less than 0.65:1.00. The proceeds of the bond can be employed for development of the ZapadnoChumpasskoye field in Russia and for general corporate purposes.The bonds included conversion features which in certain circumstances could be settled in cash and sothese 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 betweenthe $60,000,000 principal amount due on maturity and the recorded liability component is accretedand recorded as finance costs using the effective interest method. The derivative financial instrumentis 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 redeem550 outstanding bonds at 150% of par value for total proceeds of $82,500,000 plus accrued interestwhich was paid on 28 March 2007. This resulted in the recognition of a loss of $7,155,622 on theredemption, net of transaction costs, on the recorded liability and derivative liability. Previously, earlyin 2007, 50 bonds, with a total par value of $5,000,000, had been converted into 277,778 CommonShares. As a result of this conversion, a total amount of $7,104,327 was transferred to Share Capitalfrom the convertible bonds and derivative liability of the convertible bonds.203

2007 convertible bondsOn 16 February 2007, the Corporation raised $165,000,000 by completing the private placement ofconvertible bonds. Issue costs amounted to $6,979,268 resulting in net proceeds of $158,020,732. TheCorporation issued 1,650 unsecured convertible bonds at par, which have a maturity of five years andone day and an annual coupon of 8.00% payable semi-annually on 17 August and 17 February of eachyear. The bondholders had the right to convert the bonds into Common Shares at a price of $47.00 pershare at any time. The Corporation had the right to redeem, in whole or part, the bonds for cash atany time on or before 16 February 2008, at 150% of par value. This right was not exercised. Proceedswere used to finance the redemption of the outstanding of convertible bonds, issued on26 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 accruedinterest, in the event of a change of control of the Corporation or revocation or surrender of theZapadno Chumpasskoye licence in Russia. In the event of a change of control and redemption of thebonds or exercise of the conversion rights, a cash payment of up to $19,700 on each bond will be madeto the bondholder, the amount of which depends upon the date of redemption and market value atthe date of any change of control event.The bonds included conversion features which in certain circumstances could be settled in cash and sothese 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’ conversionfeature (note 23) (net of issue costs) was estimated at $17,866,517 on 16 February 2007. Thedifference between the $165,000,000 due on maturity and the initial liability component is accretedusing the effective interest method and is recorded as finance costs. The derivative financialinstrument is recorded at fair value with resulting gains and losses recorded in finance incomeand costs.In July 2007, a bondholder with US$7 million of bonds gave notice of the exercise of 70 bonds andreceived 148,937 Common Shares in August 2007. As a result of this conversion, $8,944,487 wastransferred to Share Capital from convertible bonds, derivative liability component of convertiblebonds and accrued liabilities.Pursuant to the terms of the convertible bond, the Corporation is required to provide security, in aseparate 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. InAugust 2007, the first interest payment of $6,355,108 was made from the escrow account. Cash in theescrow account, including accrued interest income, is included in cash and cash equivalents.Long-term debtIn January 2005, a wholly-owned subsidiary of the Corporation received a sterling denominated loanof £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 ofcapital 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 valuesAt 31 December 2006 and 30 September 2007, the fair values of borrowings are approximately equalto their carrying amounts as the facilities bear interest at market rates of interest.18 ProvisionsThe Group’s asset retirement obligation results from net ownership interests in petroleum and naturalgas assets including well sites and gathering systems. The Group estimates the total undiscountedinflation-adjusted amount of cash flows required to settle its asset retirement obligation to beapproximately $406,835, which is expected to be incurred in 2012 and 2024. A cost pool specificdiscount rate, related to the liability, of 9% was used to calculate the fair value of the asset retirementobligation in 2007 (2006—10%).204

A reconciliation of the asset retirement obligation is provided below:31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Balance—Beginning of period .................. 328,553 434,849 434,849 62,322Additions ................................. — 62,322 — 62,372Revision (in 2006 and 2007 due to change indiscount rate) ............................ 80,012 (41,170) (41,170) 3,204Accretion expense (note 5) .................... 26,284 26,091 26,091 5,376Liabilities transferred to discontinued operations(note 8) ................................ — (419,770) (419,770) —434,849 62,322 — 133,27419 Share capital(a) Share capitalThe authorized share capital has unlimited number of Common Shares without par value.31 December 2005 31 December 2006 30 September 2006 30 September 2007Number Amount Number Amount Number Amount Number Amount$ $ $ $Balance—Beginning ofperiod ......... 21,454,134 21,434,168 21,865,701 22,854,418 21,865,701 22,854,418 22,009,034 24,580,984Issued on exercise ofstock options(note 22) ....... 546,667 1,555,588 143,333 1,726,566 60,000 653,607 32,000 280,300Normal course issuerbids (a) ........ (135,100) (135,338) — — — — — —Issued on conversionof bonds (note 17) . — — — — — — 426,715 16,048,814Balance—End ofperiod ......... 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 bidsOn 4 November 2004, the Corporation renewed its Normal Course Issuer Bid to acquire up to1,069,506 Common Shares on the open market until 3 November 2005. This was replaced by aNormal Course Issuer Bid program that commenced on 4 November 2005 and expired on3 November 2006 and was not renewed. Pursuant to the Normal Course Issuer Bid, theCorporation could have purchased up to 1,090,785 Common Shares. In 2005, the Corporationacquired 135,100 Common Shares at an average price of Cdn$7.85 per share for cancellation. Noacquisitions under the Normal Course Issuer Bid were made in 2006.205

20 Reserves and retained earnings (deficit)(a) Reserves31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Available-for-sale investments revaluationreserve .......................... — — — 168,000Foreign currency translation reserve ....... — (4,003) — 133,768— (4,003) — 301,768Share-based payments reserve ........... 973,956 2,641,061 1,363,795 34,781,494973,956 2,637,058 1,363,795 35,083,262MovementsAvailable-for-sale investments revaluationreserveBalance—Beginning of period ........... — — — —Revaluation ......................... — — — 168,000Balance—End of period ................ — — — 168,000Foreign currency translation reserveBalance—Beginning of period ........... — — — (4,003)Currency translation differences arisingduring period ...................... — (4,003) — 137,771Balance—End of period ................ — (4,003) — 133,768Share-based payments reserveBalance—Beginning of period ........... 24,421 973,956 973,956 2,641,061Compensation costs—options issued ....... 1,082,112 2,074,727 441,253 32,365,616Transfer to share capital on exercise ofoptions .......................... (132,577) (407,622) (51,414) (81,376)Options forfeited ..................... — — — (143,807)Balance—End of period ................ 973,956 2,641,061 1,363,795 34,781,494(b) Retained earnings (deficit)31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Balance—Beginning of period ....... 52,879,284 43,876,180 43,876,180 15,508,425Premium on repurchase andcancellation 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 reservesi) Available-for-sale investments revaluation reserveChanges in the fair value and exchange differences arising on translation of available for saleinvestments such as equities, classified as available-for-sale financial assets, are taken to theavailable-for-sale investments revaluation reserve, as described in note 1(k). Amounts arerecognised in profit and loss when the associated assets are sold or impaired.ii) Foreign currency translation reserveExchange differences arising on retranslation of the foreign controlled entity are taken to theforeign currency translation reserve, as described in note 1(t). The reserve will be recognisedin the income statement when the net investment is disposed.iii) Share-based payments reserveThe share-based payments reserve is used to recognise the fair value of options issued, butnot exercised, to employees.206

21 Loss per shareThe following table summarizes the weighted average Common Shares used in calculating netearnings per share:Nine-month periods endedYear ended 31 December30 September2005 2006 2006 2007(Unaudited)Weighted average Common SharesBasic ............................... 21,650,215 21,917,363 21,895,628 22,317,412Diluted ............................. 21,860,371 22,095,507 22,045,516 23,284,968The reconciling item between basic and diluted weighted average number of Common Shares is thedilutive 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 tothe 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 paymentsStock optionsThe Corporation has a stock option plan whereby certain directors, officers, employees andconsultants of the Group may be granted options to purchase Common Shares. Under the terms ofthe plan, options granted normally vest one third immediately and one third in each of the yearsfollowing the date granted and have a life of five years.Common Share options outstanding and exercisable:31 December 2005 31 December 2006Number Average Number Averageof options exercise price of options exercise price(Cdn) $ (Cdn) $Balance—Beginning of period ............... 476,667 1.31 425,000 9.57Granted ............................... 495,000 10.40 550,000 27.98Exercised (note 19) ...................... (546,667) 3.12 (143,333) 10.27Balance—End of period ................... 425,000 9.57 831,667 21.63Exercisable—End of period ................ 194,998 9.42 350,002 18.8930 September 2006 30 September 2007Number Average Number Averageof options exercise price of options exercise price(Cdn) $ (Cdn) $(Unaudited)Balance—Beginning of period .............. 425,000 9.57 831,667 21.63Granted .............................. 15,000 16.60 1,320,701 29.14Exercised (note 19) ...................... (60,000) 11.06 (32,000) 6.65Forfeited .............................. — — (41,667) 9.70Balance—End of period ................... 380,000 9.61 2,078,701 26.87Exercisable—End of period ................ 225,002 9.30 836,567 23.93Number of optionsRemainingExercise 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 4.202,078,701 836,567 4.04207

During the nine-month period ended 30 September 2007, the weighted average share price at the dateof option exercise was Cdn $41.97. (Cdn $18.36 during the nine-month period ended 30 September2006).The fair value of each stock option grant on the date of grant was estimated using the Black-Scholesoption-pricing model with the following weighted average assumptions and results. The fair value ofstock options is amortised over the vesting period of the option.31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Weighted average assumption and resultsRisk free interest rate (%) ........................... 2.81 4.13 2.12 4.55Volatility (%) .................................... 58.86 42.99 62.40 45.00Dividend yield (%) ................................ — — — —Expected life (years) ............................... 3.80 3.42 5.00 3.00Grant date fair value (Cdn $) ........................ 3.93 8.80 9.11 32.1923 Derivative financial liability31 December 30 September2005 2006 2006 2007$ $ $ $(Unaudited)Convertible bond — conversion option ........ — 27,997,140 8,621,068 32,810,103For details of the convertible bond, refer to note 17.The fair value of the convertible bonds conversion option has been estimated using the Black-Scholesoption-pricing model at each period end, with changes in the fair value of the conversion optionrecognised in income during the period. The expected life of the conversion option has been adjustedto reflect the bondholders’ put option and the Corporation’s redemption option as detailed in note 17.24 Related party transactionsDuring the nine-month period ended 30 September 2007, general and administrative expensesincluded an advisory fee of $806,607 (30 September 2006—$644,258) charged by Mr. AnthonyBuckingham, 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 Groupacquired 605,000 common shares of Sea Dragon on 9 March 2007 through the sale of its 65% interestin 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 officein Switzerland that required this same director to relocate; he received a relocation allowanceof $275,918.208

25 Commitments and contingenciesHeritage’s net share of outstanding contractual commitments at 30 September 2007 was estimated at:Less thanAfterTotal 1 year 1-3 years 4-5 years 5 years$’000 $’000 $’000 $’000 $’000Long-term debt ......................... 17,662 617 1,234 8,334 7,477Convertible bonds ....................... 158,000 — — 158,000 —Total repayments of borrowings ............. 175,662 617 1,234 166,334 7,477Operating leases ........................ 9,642 229 458 458 8,497Other long-term obligations ................ 140,000 40,000 100,000 — —Work program obligations ................. 124,759 58,236 52,259 14,065 200Total contractual obligations ................ 274,401 98,465 152,717 14,523 8,697The Corporation may have a potential residual obligation to satisfy any shortfall in officers’ andformer officers’ secured real estate borrowings in the event of default, a shortfall on the proceedsfrom the disposal of the properties and the individuals being unable to repay the balance. The value ofthe residual obligation was estimated as insignificant.On 6 October 2006, the Corporation released Mr. Micael Gulbenkian from his role as its Chairmanand Chief Executive Officer.In many of the countries in which the Group operates, land title systems are not developed to theextent found in many industrial countries and there may be no concept of registered title. Althoughthe Group believes that it has title to its oil and gas properties, it cannot control or completely protectitself against the risk of title disputes or challenges. There can be no assurance that claims orchallenges by third parties against the Group’s properties will not be asserted at a future date. TheGroup received a letter from the Iraq Ministry of Oil dated 17 December 2007 stating that theProduction 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 governmentas they have stated it violates the ‘‘prevailing Iraqi law’’. On the basis of the KRI legal advice, theDirectors 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 thegrant of a presidential decree from the DRC government. There can be no assurance that finalapproval or ratification will ever be received in respect of the DRC PSC or that the pre-agreed fiscalterms 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 theNational Oil Corporation of Libya dated 28 February 2008 stating that the Block 7 licence area lieswithin the Libyan continental shelf and a portion of this area has already been licensed to Sirte OilCompany. This letter also demands that the Group refrain from any activities over or concerning theBlock 7 licence area and asserts the Libyan government’s right to invoke Libyan and international lawto protect its rights in the Block 7 licence area. The Directors believe that the Libyan government’sclaims are unfounded.209

26 Non-cash investing and financing activitiesYear ended Nine-month periods ended31 December 30 September2005 2006 2006 2007$ $ $(Unaudited)Capitalised portion of stock-based compensation ...... — (940,000) — (8,957,752)Non-cash property, plant and equipment additionsrelating to the capitalised portion of stock-basedcompensation .............................. — 940,000 — 8,957,752Non-cash portion of sales proceeds on disposal ofdiscontinued operations ...................... — 719,380 — —Receipt of warrant as part of the sales proceeds fromthe 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 disposalof subsidiaries (note 9) ....................... — — — 2,420,000Receipt of SeaDragon shares as a result of the issuanceof the Corporation’s guarantee for a third party’s debt — — — 435,000Accrual of payable representing the fair value of theCorporation’s guarantee issued for a third party’s debt — — — (435,000)27 Subsequent eventsIn October 2007, a wholly-owned subsidiary of the Corporation received a loan of U.S.$9,450,000 torefinance the corporate jet acquisition. Interest on the loan is variable at a rate of LIBOR plus1.6 per cent. The loan, which is secured on the corporate jet, is scheduled to be repaid by19 consecutive quarterly installments of principal. Each installment equals to $117,500 with the finalinstallment 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 SharingContract with the Kurdistan Regional Government (KRG) over Miran Block in the southern region ofthe Kurdistan Region of Iraq. Heritage will also be operating as a 50/50 partner with the KRG tosupply and operate a 20,000 barrel per day oil refinery in the vicinity of the licence area (‘‘RefineryAgreement’’). The Production Sharing Contract and Refinery Agreement include minimum workprogram and contractual commitments estimated at approximately $40 million and $140 millionrespectively, over four years.On 14 November, 2007, the Corporation closed an equity offering of 3,000,000 Common Shares whichwere issued at a price of Cdn $60.50 per Common Share for gross proceeds of Cdn $181.5 million tothe Company. In addition, Albion Energy Limited sold 3,000,000 Common Shares at a price ofCdn $60.50 per Common Share for gross proceeds of Cdn $181.5 million. The ultimate owner ofAlbion Energy is Mr. Anthony Buckingham, a Director and Chief Executive Officer of theCorporation.In November 2007, a wholly-owned subsidiary of the Group was awarded a 60 per cent. participatinginterest in the Sanjawi Block in Zone II (Baluchistan), in Pakistan. The onshore exploration licencehas a gross area of 2,258 square km. The exploration licence and PSC were executed on16 November 2007. The Group has been appointed as an operator. The work programme shall befully completed during initial three year term with financial commitment of $3.3 million in the firstyear, $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 Governmentfor Areas 2 and 7 in the southeastern offshore region of Malta. Under the terms of the agreement, awholly-owned subsidiary of the Group will serve as operator with a 100% interest. Areas 2 and 7 coverapproximately 9,190 square km and 8,778 square km respectively. The total minimum contractualwork programme has financial commitment of $22 million, distributed over the first three-yearexploration 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 asoperator. Wholly owned subsidiaries of the Corporation have acquired a 75% working interest inBlock 7 and Block 11. In return for earning the working interest the Corporation will fund all costs ofthe obligatory work programs for the next two years in both blocks, at a total estimated cost for thetwo licenses of between $15 million and $20 million.In February 2008, the Corporation announced that it will enter into a corporate reorganisation whichwill result in a newly incorporated company, Heritage Oil Limited (‘‘Heritage Jersey’’), becoming theparent company of the Corporation and its current subsidiaries.In connection with this reorganisation Heritage Jersey has agreed that, provided the reorganisation iscompleted, the 2007 Convertible Bonds outstanding at that date will be convertible with shares ofHeritage Jersey rather than shares of the Corporation.28 Explanation of transition to IFRSReconciliation of equity reported under previous Canadian Generally Accepted Accounting Principles(CGAAP) to equity under International Financial Reporting Standards (IFRS):At the date of transition IFRS—1 January 2005Effect ofPrevious transitionNotes CGAAP to IFRS IFRS$ $ $AssetsNon-current assetsIntangible exploration assets ........... (b),(c) — 32,725,642 32,725,642Intangible development costs .......... 1,013,012 — 1,013,012Property, plant and equipment ......... (a),(b),(d),(g) 54,083,097 (32,306,191) 21,776,90655,096,109 419,451 55,515,560Current assetsInventories ....................... (d) 94,483 24,976 119,459Prepaid expenses ................... 272,168 — 272,168Trade and other receivables ........... 8,920,963 — 8,920,963Cash and cash equivalents ............ 16,235,523 — 16,235,52325,523,137 24,976 25,548,11380,619,246 444,427 81,063,673LiabilitiesCurrent liabilityTrade and other payables ............. 6,397,247 — 6,397,247Non-current liabilityProvisions ........................ 328,553 — 328,5536,725,800 — 6,725,80073,893,446 444,427 74,337,873EquityShare capital ...................... 21,434,168 — 21,434,168Reserves ......................... 24,421 — 24,421Retained earnings .................. (a)(c)(d)(g) 52,434,857 444,427 52,879,28473,893,446 444,427 74,337,873211

At the end of the comparative period under previous CGAAP—31 December 2005Effect ofPrevious transitionNotes CGAAP to IFRS IFRS$ $ $AssetsNon-current assetsIntangible exploration assets ........ (b),(c),(f) — 43,503,704 43,503,704Intangible development costs ........ 1,187,371 — 1,187,371Property, plant and equipment ....... (a),(b),(d),(g) 74,729,540 (49,446,988) 25,282,55275,916,911 (5,943,284) 69,973,627Current assetsInventories ..................... (d) 216,474 35,441 251,915Prepaid expenses ................ 219,222 — 219,222Trade and other receivables ......... 1,318,450 — 1,318,450Cash and cash equivalents .......... 8,583,321 — 8,583,32110,337,467 35,441 10,372,90886,254,378 (5,907,843) 80,346,535LiabilitiesCurrent liabilitiesTrade and other payables .......... 4,438,649 — 4,438,649Borrowings ..................... 248,045 — 248,0454,686,694 — 4,686,694Non-current liabilitiesBorrowings ..................... 7,520,438 — 7,520,438Deferred tax liabilities ............. (f) 2,346,605 (2,346,605) —Provisions ...................... 434,849 — 434,84910,301,892 (2,346,605) 7,955,28714,988,586 (2,346,605) 12,641,981EquityShare capital ................... 22,854,418 — 22,854,418Reserves ....................... (e) 517,209 456,747 973,956Retained earnings (deficit) ......... (a),(c),(d),(e),(g) 47,894,165 (4,017,985) 43,876,18071,265,792 (3,561,238) 67,704,554212

Reconciliation of loss for the year ended 31 December 2005Effect ofPrevious transitionNotes CGAAP to IFRS IFRS$ $ $RevenuePetroleum and natural gas ............... 841,766 — 841,766Drilling services ....................... 342,359 — 342,3591,184,125 — 1,184,125ExpensesPetroleum and natural gas ............... 465,110 — 465,110Drilling rig operating ................... 196,804 — 196,804General and administrative .............. (e) 5,249,649 456,747 5,706,396Foreign exchange losses ................. 1,170,906 — 1,170,906Depletion, depreciation and amortisation .... (c),(d),(g) 536,093 202,537 738,630Exploration expenditure ................. (a) — 4,517,411 4,517,411Impairment of unproved petroleum andnatural gas interest ................... (a) 724,915 (724,915) —8,343,477 4,451,780 12,795,257Finance income (costs)Interest income ....................... 330,290 — 330,290Finance 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) 3,510,441Net loss ............................ (3,799,813) (4,462,412) (8,262,225)213

Reconciliation of cash flow statement for the year ended 31 December 2005Effect ofPrevious transition toNotes CGAAP IFRS IFRS$ $ $Cash provided by (used in)Operating activitiesNet loss from continuing operations . . (a),(c),(d),(e),(g) (7,320,886) (4,451,780) (11,772,666)Items not involving cashDepletion, depreciation andamortisation ................ (c),(d),(g) 536,093 202,537 738,630Finance costs — accretion expenses . — — —Foreign exchange losses .......... 480,253 — 480,253Stock-based compensation ........ (e) 625,365 456,747 1,082,112Impairment of unproved petroleumand natural gas properties ...... (a) 724,915 (724,915) —Increase in trade and otherreceivables ................. (258,398) — (258,398)Decrease in prepaid expenses ..... 1,921,678 — 1,921,678Increase 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 — 4,034,035697,123 (4,517,411) (3,820,288)Investing activitiesProperty, plant and equipmentexpenditures .................. (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 activitiesShares issued for cash ............ 1,423,011 — 1,423,011Long-term debt ................. 8,577,350 — 8,577,350Purchase of Common Shares forcancellation .................. (876,217) — (876,217)Repayment of long-term debt ....... (103,997) — (103,997)9,020,147 — 9,020,147Foreign exchange losses on cash heldin 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 — 16,235,523Cash and cash equivalents — End ofyear ........................ 8,583,321 — 8,583,321214

At the end of the last reporting period under previous CGAAP—31 December 2006Effect ofPrevious transitionNotes CGAAP to IFRS IFRS$ $ $AssetsNon-current assetsIntangible exploration assets (b)(c)(f)(k) — 54,767,332 54,767,332Intangible developmentcosts ................ 1,574,039 — 1,574,039Property, plant andequipment ........... (a)(b)(d)(f)(g)(h)(k) 98,311,833 (66,124,735) 32,187,098Deferred financing fees .... (i) 2,539,726 (2,539,726) —Other financial assets (j) 719,380 195,178 914,558103,144,978 (13,701,951) 89,443,027Current assetsInventories ............. (d)(g) 50,552 48,369 98,921Prepaid expenses ........ 531,273 — 531,273Trade and other receivables . 9,839,506 — 9,839,506Cash and cash equivalents . . 46,861,146 — 46,861,14657,282,477 48,369 57,330,846160,427,455 (13,653,582) 146,773,873LiabilitiesCurrent liabilitiesTrade and other payables . . 12,715,381 — 12,715,381Borrowings ............. 147,720 — 147,72012,863,101 — 12,863,101Non-current liabilitiesBorrowings ............. (i) 65,525,524 (2,400,681) 63,124,843Provisions ............. 62,322 — 62,322Deferred tax liabilities ..... (f) 2,346,605 (2,346,605) —Derivative financial liability . (l) — 27,997,140 27,997,14067,934,451 23,249,854 91,184,30580,797,552 23,249,854 104,047,40679,629,903 (36,903,436) 42,726,467EquityShare capital ........... (i)(l) 27,865,874 (3,284,890) 24,580,984Reserves .............. (e)(k) 2,533,532 103,526 2,637,058Retained earnings (deficit) . (a)(c)(d)(e)(g)(h)(j)(k)(l) 49,230,497 (33,722,072) 15,508,42579,629,903 (36,903,436) 42,726,467215

Reconciliation of loss for the year ended 31 December 2006Effect ofPrevious transitionNotes CGAAP to IFRS IFRS$ $ $RevenuePetroleum and natural gas ................ 3,938,512 — 3,938,512Drilling services ........................ 2,895,727 — 2,895,7276,834,239 — 6,834,239ExpensesPetroleum and natural gas ................ 723,611 — 723,611Drilling rig operating .................... 2,291,585 — 2,291,585General and administrative ................ (e) 8,977,345 (349,218) 8,628,127Foreign exchange losses (gains) ............ (k) 798,194 (171,189) 627,005Depletion, depreciation and amortisation ..... (d)(g) 691,011 660,976 1,351,987Exploration expenditure .................. (a) — 6,066,977 6,066,977Impairment of unproved petroleum andnatural gas .......................... (a) 986,964 (986,964) —14,468,710 5,220,582 19,689,292Finance income (costs)Interest income ........................ (h) 1,767,898 (431,547) 1,336,351Finance 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 discontinuedoperations .......................... (g)(h) 9,950,968 (750,268) 9,200,700Earnings from discontinued operations ....... 3,248,490 — 3,248,490Net loss ............................. (f) 1,336,332 (29,704,087) (28,367,755)216

Reconciliation of cash flow statement for the year ended 31 December 2006Effect ofPrevious transitionNotes CGAAP to IFRS IFRS$ $ $Cash provided by (used in)Operating activitiesNet loss from continuingoperations .............. (a)(d)(e)(g)(h)(i)(k)(l) (11,863,126) (28,953,819) (40,816,945)Items not involving cashDepletion, depreciation andamortisation ........... (d)(g) 691,011 660,976 1,351,987Finance costs—accretionexpenses .............. (h) 860,895 (213,442) 647,453Foreign exchange losses .... (k) 593,837 (171,189) 422,648Stock-based compensation . . (e) 1,483,945 (66,901) 1,417,044Impairment of unprovedpetroleum and natural gasproperties ............. (a) 986,964 (986,964) —Gain on other financial assets (j) — (195,178) (195,178)Loss on derivative financialinstruments ........... (l) — 24,851,295 24,851,295Increase in trade and otherreceivables ............ (972,251) — (972,251)Increase in prepaid expenses . (312,051) — (312,051)Decrease in inventory ...... 142,809 — 142,809Increase in trade and otherpayables .............. 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 activitiesProperty, plant and equipmentexpenditures ............ (a)(b)(h) (33,512,387) 21,247,324 (12,265,063)Intangible explorationexpenditures ............ (a)(b)(h) — (16,172,102) (16,172,102)Intangible developmentexpenditures ............ (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 activitiesShares issued for cash ....... 1,318,945 — 1,318,945Convertible bonds .......... 60,000,000 — 60,000,000Convertible bond issue costs . . . (3,000,000) — (3,000,000)Repayment of long-term debt . . (287,759) — (287,759)58,031,186 — 58,031,186Decrease in cash and cashequivalents ............. 37,794,871 — 37,794,871Cash and cash equivalents—Beginning of year ......... 8,583,321 — 8,583,321Foreign exchange gains on cashheld in foreign currency .... 482,954 — 482,954Cash and cash equivalents—End of year ............. 46,861,146 — 46,861,146217

Notes to reconciliationsa) Pre-licence costsUnder Canadian GAAP all costs incurred prior to having obtained licence rights were includedwithin 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 andequipment and retained earnings of $2,162,301.At 31 December 2005, this adjustment has resulted in a reduction in property, plant andequipment and retained earnings of $5,954,797, an increase in exploration expenditure for theyear of $4,517,411, and a decrease in the impairment of unproved petroleum and natural gasinterests recognised in the year of $724,915. The income tax impact was in a further reduction ofproperty, plant, and equipment of $2,346,605 and a corresponding decrease in deferred taxliability.At 31 December 2006, this adjustment has resulted in a reduction in property, plant andequipment and retained earnings at $11,034,810, an increase in exploration expenditure for theyear of $6,066,977, and a decrease in the impairment of unproved petroleum and natural gasinterests recognised in the year of $986,964.b) Reclassification of exploration and evaluation costsUnder Canadian GAAP property, plant and equipment included certain exploration andevaluation expenditure incurred within established geographic cost pools. Under IFRS, suchexploration 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 equipmentto intangible exploration assets of $56,311,426 (1 January 2005—$32,589,744; 31 December2005—$45,111,919).c) Capitalisation of property, plant and equipment depreciation of intangible assetsUnder IFRS, depreciation of property, plant and equipment utilised in exploration activities iscapitalised as intangible exploration assets. As these assets were classified as property, plant andequipment 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 assetsand retained earnings of $135,898. At 31 December 2005, an increase in intangible explorationassets 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 earningsof $171,728.d) Reversal of impairmentUnder IFRS, impairment losses previously recorded are reversed if the conditions giving rise tothe impairment have reversed. The reversal of impairment losses was not permitted underCanadian GAAP. The impact on adoption to IFRS at 1 January 2005 is an increase in inventoryof $24,976, an increase in property, plant and equipment of $1,656,846, and an increase inretained earnings of $1,681,822.At 31 December 2005, this has resulted in increases in inventory of $35,441, property, plant andequipment of $1,442,748, retained earnings of $1,478,189, and depletion expense for the yearof $203,633.At 31 December 2006, this has resulted in increases in inventory of $26,638, property, plant andequipment of $1,071,212, retained earnings of $1,097,850 and depletion expense for the yearof $380,339.e) Share-based paymentsUnder Canadian GAAP, the Group recognised an expense related to their share-based paymentson a straight-line basis through the date of full vesting. Under IFRS, the Group is required torecognise 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 andshare-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 administrativeexpenses for the year decreased by $349,218.f) Deferred taxUnder Canadian GAAP, the Corporation recognised a deferred tax liability and correspondingincrease 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 isacquired through a business combination.At 31 December 2005 and 31 December 2006, this has resulted in a reduction of property, plantand equipment and deferred tax liability of $2,346,605. There was no impact at 1 January, 2005.g) Depletion policyUpon transition to IFRS, the Corporation adopted a policy of depleting petroleum and naturalgas interests on a units of production basis over proved plus probable reserves. The depletionpolicy 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 andequipment and retained earnings of $789,008. At 31 December 2005, this resulted in increases inproperty, plant and equipment and retained earnings of $743,642, and depletion expense for theyear of $34,734, and a decrease in earnings from discontinued operations of $10,632. At31 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, andincreases in inventory of $21,731, and depletion expense for the year of $280,637.h) Capitalisation of borrowing costsUnder Canadian GAAP all borrowing costs were expensed as incurred. Under IFRS, theCorporation 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 andretained 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 feesUnder IFRS, loans and receivables are recognised net of transaction costs, with interest expenserecognised over the term of the loan using the effective interest method. Under Canadian GAAPprior to 1 January, 2007, the Corporation recognised these transaction costs as deferred financingfees in non-current assets and amortised them into income on a straight-line basis over the termof 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 assetsIFRS requires held for trading financial assets to be measured at fair value with changes in thefair value to be recorded in income in the period. Under Canadian GAAP, these assets were heldat 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 earningsand unrealised gain on other financial assets of $195,178.k) Foreign currency translationUnder IFRS, amounts are initially recognised in a subsidiary’s functional currency (the currencyof the primary economic environment in which it operates) and are translated into the functionalcurrency of the group in accordance with note 1(t). The assessment of functional currency hasresulted in transactions and balances for the Corporation’s Russian subsidiary to be initiallyrecognised in Russian roubles. Under Canadian GAAP, these subsidiaries were considered to beintegrated and were translated with only monetary assets and liabilities retranslated using periodend 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, withdecreases in foreign exchange losses of $171,189 and the foreign currency translation reserveof $4,003.l) Convertible bondsUnder Canadian GAAP, the Corporation’s convertible bonds were initially recognised with anallocation between equity and liability components based on their relative fair values. IFRSrequires the recognition of a liability and an embedded derivative liability representing the bondholder’s conversion option. The fair value of the derivative financial liability is subsequentlymeasured 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 othercontributed equity of $3,145,845, and retained earnings of $24,851,295.220

AUDITED FINANCIAL STATEMENTS RELATING TO HOC PREPARED IN ACCORDANCE WITHCANADIAN GAAPSet out on the following pages are:a) a letter from KPMG LLP, Calgary, Canada, consenting to the inclusion in this document of theiraudit report dated 22 March 2006 (and with respect to note 13, 28 March 2006) relating to theconsolidated financial statements of HOC for the two years ended and as at 31 December 2005;andb) the audit report of KPMG LLP, Calgary, Canada, relating to the consolidated financialstatements of HOC for the two years ended and as at 31 December 2005; andc) the consolidated financial statements of HOC for the two years ended and as at 31 December2005 prepared in accordance with Canadian GAAP letter of consent.221

AUDITORS’ CONSENTThe Board of Directors of Heritage Oil LimitedWe have read the UK prospectus (‘‘the Prospectus’’) proposed to be filed by Heritage Oil Limited inaccordance with the Prospectus Directive Regulation and the Prospectus Rules of the Financial ServicesAuthority of the United Kingdom dated March 28, 2008 relating to the proposed admission to listing andtrading of Heritage Oil Limited on the main market of the London Stock Exchange plc. We have compliedwith 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 OilLimited on the consolidated balance sheets of Heritage Oil Corporation as at December 31, 2005 and 2004and the consolidated statements of earnings (loss) and retained earnings and cash flows for each of theyears in the two-year period ended December 31, 2005. Our report is dated March 22, 2006 (except as tonote 13 which is as of March 28, 2006).(Signed) ‘‘KPMG LLP’’Chartered AccountantsCalgary, CanadaMarch 28, 2008222

AUDITORS’ REPORT TO THE SHAREHOLDERSWe have audited the consolidated balance sheets of Heritage Oil Corporation as at December 31, 2005 and2004 and the consolidated statements of earnings (loss) and retained earnings and cash flows for the yearsthen ended. These financial statements are the responsibility of the Corporation’s management. Ourresponsibility 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. Thosestandards require that we plan and perform an audit to obtain reasonable assurance whether the financialstatements are free of material misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements. An audit also includes assessing theaccounting principles used and significant estimates made by management, as well as evaluating the overallfinancial statement presentation.In our opinion, these consolidated financial statements present fairly, in all material respects, the financialposition of the Corporation as at December 31, 2005 and 2004 and the results of its operations and its cashflows for the years then ended in accordance with Canadian generally accepted accounting principles.8FEB200818093203Chartered AccountantsCalgary, CanadaMarch 22, 2006, except note 13 which is as of March 27, 2006223

HERITAGE OIL CORPORATIONCONSOLIDATED BALANCE SHEETSDecember 31, 2005 and 2004(U.S. dollars)2005 2004$ $ASSETSCURRENT ASSETS:Cash and cash equivalents .................................... 8,583,321 16,235,523Accounts receivable ......................................... 1,318,450 4,640,802Note receivable (note 7) ..................................... — 4,280,161Inventories ............................................... 216,474 94,483Prepaid expenses ........................................... 219,222 272,16810,337,467 25,523,137Property and equipment (note 3) ................................. 72,382,935 54,083,097Deferred development costs (note 4) .............................. 1,187,371 1,013,01283,907,773 80,619,246LIABILITIES AND SHAREHOLDERS’ EQUITYCURRENT LIABILITIES:Accounts payable and accrued liabilities .......................... 4,438,649 6,397,247Current portion of long-term debt .............................. 248,045 —4,686,694 6,397,247Long-term debt ............................................. 7,520,438 —Asset retirement obligations (note 5) .............................. 434,849 328,553SHAREHOLDERS’ EQUITY:Share capital and warrants (note 6 (b)) ........................... 22,854,418 21,434,168Contributed surplus (note 6 (g)) ................................ 517,209 24,421Retained earnings .......................................... 47,894,165 52,434,85771,265,792 73,893,446Commitments (note 12)Subsequent events (note 13)83,907,773 80,619,246See accompanying notes to consolidated financial statements.On behalf of the Board:MICAEL GULBENKIANDirectorPAUL ATHERTONDirector224

HERITAGE OIL CORPORATIONCONSOLIDATED STATEMENTS OF EARNINGS (LOSS) AND RETAINED EARNINGSYears ended December 31, 2005 and 2004(U.S. dollars)2005 2004$ $REVENUE:Petroleum and natural gas ...................................... 6,286,702 5,592,721Interest ................................................... 371,651 560,926Other ..................................................... 1,355,369 443,3358,013,722 6,596,982EXPENSES:Operating .................................................. 1,653,657 1,442,016Royalties .................................................. 816,740 345,656General and administrative ..................................... 5,249,862 2,633,667Interest ................................................... 491,824 —Foreign exchange (gains) losses .................................. 1,240,529 (1,488,026)Depletion, depreciation and accretion ............................. 1,636,008 633,643Write-down of unproved petroleum and natural gas interest (note 3) ....... 724,915 934,77111,813,535 4,501,727Earnings (loss) before the undernoted ............................. (3,799,813) 2,095,255Gain on sale of property and equipment (note 7) ..................... — 26,269,113Net earnings (loss) ........................................... (3,799,813) 28,364,368Retained earnings, beginning of year .............................. 52,434,857 24,028,812Effect of change in accounting for:Asset retirement obligations (note 5) ............................ — 55,558Stock-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 52,434,857Net earnings (loss) per share (note 6 (f)):Basic ..................................................... (0.18) 1.33Diluted ................................................... (0.18) 1.31See accompanying notes to consolidated financial statements.225

HERITAGE OIL CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWSYears ended December 31, 2005 and 2004(U.S. dollars)2005 2004CASH PROVIDED BY (USED IN):OPERATING:Net earnings (loss) ........................................ $ (3,799,813) $ 28,364,368Items not involving cash:Gain on sale of property and equipment (note 7) .................. — (26,269,113)Depletion, depreciation and accretion .......................... 1,636,008 633,643Foreign exchange (gains) losses ............................... 480,253 (1,910,662)Stock-based compensation ................................... 625,365 10,540Write-down of unproved petroleum and natural gas interests (note 3) . . 724,915 934,771Changes in non-cash operating working capital .................... 1,030,395 102,462697,123 1,866,009FINANCING:Shares issued for cash ...................................... 1,423,011 604,953Long-term debt .......................................... 8,577,350 —Purchase of Common Shares for cancellation ..................... (876,217) —Repayment of long-term debt ................................ (103,997) —9,020,147 604,953INVESTING:Property and equipment expenditures .......................... (20,554,465) (37,318,136)Proceeds on sale of property and equipment ..................... — 16,400,000Repayment of note receivable ................................ 4,210,538 10,724,500Development 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) 906,001Decrease in cash and cash equivalents .......................... (7,652,202) (7,933,349)Cash and cash equivalents, beginning of year ..................... 16,235,523 24,168,872Cash and cash equivalents, end of year ......................... $ 8,583,321 $ 16,235,523Supplementary information:Interest received .......................................... $ 397,640 $ 556,897Interest paid ............................................. $ 491,824 —See accompanying notes to consolidated financial statements.226

HERITAGE OIL CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTSYears 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 petroleumand natural gas in the Middle East, Africa and Russia.The preparation of the consolidated financial statements in conformity with Canadian generally acceptedaccounting principles requires management to make estimates and assumptions that affect the reportedamounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of theconsolidated financial statements and the reported amounts of revenue and expenses during the reportingperiods. 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 subsidiariesand its proportionate interests in corporate joint ventures.The majority of the Corporation’s business is transacted in U.S. dollars and, accordingly, thefunctional and reporting currency is U.S. dollars.(b) Joint operations:Substantially all exploration, development and production activities are conducted jointly withothers 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 investmentswith 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 thelower 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 gasoperations, whereby all costs related to the acquisition, exploration and development ofpetroleum and natural gas interests are accumulated within cost centres on a country-by-countrybasis. Such costs include land acquisition costs, geological and geophysical expenses, carryingcharges on non-producing interests, costs of drilling both productive and non-productive wells,major development projects and overhead charges directly relating to acquisition, explorationand development activities.Proceeds from the sale of petroleum and natural gas interests are applied against capitalized costsexcept for sales that would change the rate of depletion and depreciation by 20% or more, inwhich case a gain or loss is recorded.Capitalized costs, together with estimated future capital costs associated with proved reserves, aredepleted and depreciated using the unit of production method based on estimated gross provedreserves of petroleum and natural gas as determined by independent engineers. For purposes ofthis calculation, reserves and production are converted to equivalent units of petroleum based onrelative 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 areexcluded from costs subject to depletion and depreciation until it is determined that provedreserves 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 methodrequires a detailed impairment calculation when events or circumstances indicate a potentialimpairment 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 recoverableand exceeds its fair value. The carrying amount is assessed to be recoverable when the sum of theundiscounted cash flows expected from proved reserves plus the cost of unproved interests, net ofimpairments, exceeds the carrying amount of the cost centre. When the carrying amount isassessed not to be recoverable, an impairment loss is recognized to the extent that the carryingamount of the cost centre exceeds the sum of the discounted cash flows from proved andprobable reserves plus the cost of unproved interests, net of impairments, of the cost centre. Thecash flows are estimated using expected future product prices and costs and are discounted usinga risk-free interest rate.Drilling rig equipment is depreciated using the unit-of-production method based on 2,740 drillingdays 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)(g)Asset retirement obligations:The Corporation records the fair value of an asset retirement obligation as a liability in theperiod in which it incurs a legal obligation associated with the retirement of tangible long-livedassets that result from the acquisition, construction, development, and/or normal use of theassets. The associated asset retirement costs are capitalized as part of the carrying amount of thelong-lived asset and depleted and depreciated using a unit of production method over estimatedgross 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 changesin the estimated future cash flows underlying the obligation.Deferred development costs:Development costs related to specific projects that in the Corporation’s view have a clearlydefined future market are deferred and amortized on a straight line basis commencing in the yearfollowing that in which the new product development was completed. All other research anddevelopment 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 anexternal party.(i)(j)Income taxes:The Corporation uses the asset and liability method of accounting for income taxes. Under theasset and liability method, future tax assets and liabilities are recognized for the future taxconsequences attributable to differences between the financial statement carrying amounts ofexisting assets and liabilities and their respective tax bases. Future tax assets and liabilities aremeasured using enacted or substantively enacted tax rates expected to apply to taxable income inthe years in which those temporary differences are expected to be recovered or settled. The effecton future tax assets and liabilities of a change in tax rates is recognized in income in the periodthat includes the date of enactment or substantive enactment.Derivative financial instruments:The Corporation uses derivative financial instruments from time to time to hedge its exposure tocommodity price fluctuations. The Corporation does not enter into derivative financialinstruments for trading or speculative purposes.The derivative financial instruments are initiated within the guidelines of the Corporation’s riskmanagement policy. This includes linking all derivatives to specific firm commitments orforecasted transactions. The Corporation believes the derivative financial instruments are228

effective as hedges, both at inception and over the term of the instrument, as the term andnotional amount do not exceed the Corporation’s firm commitment or forecasted transaction andthe underlying basis of the instrument matches the Corporation’s exposure.The Corporation enters into hedges of its exposure to petroleum and natural gas commodityprices by entering into crude oil and natural gas swap contracts, options or collars when it isdeemed appropriate. These derivative contracts, accounted for as hedges, are not recognized onthe balance sheet. Realized gains and losses on these contracts are recognized in petroleum andnatural gas revenue in the same period in which the revenues associated with the hedgedtransaction are recognized. Premiums paid or received are deferred and amortized to earningsover the term of the contract.(k) Foreign currency translation:Monetary items denominated in foreign currencies are translated to U.S. dollars at exchangerates in effect at the balance sheet date and non-monetary items are translated at rates ofexchange in effect when the assets were acquired or obligations incurred. Revenue and expensesare translated at rates in effect at the time of the transactions. Foreign exchange gains and lossesare included in earnings.(l)Stock based compensation plan:The Corporation has a stock-based compensation plan, which is described in note 6. TheCorporation accounts for all stock-based payments granted on or after January 1, 2002, using thefair value based method.Under the fair value based method, stock-based payments are measured at the fair value of theconsideration 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-employeesis periodically re-measured until counterparty performance is complete, and any change therein isrecognized over the period and in the same manner as if the Corporation had paid cash instead ofpaying with or using equity instruments. The cost of stock-based payments to non-employees thatare 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 toJanuary 1, 2004. Consideration paid by employees on the exercise of stock options is recorded asshare capital. The Corporation discloses the pro forma effect of accounting for these awardsunder the fair value based method.(m) Per share amounts:Basic per share amounts are computed by dividing net earnings by the weighted average sharesoutstanding during the reporting period. Diluted per share amounts are computed similar tobasic per share amounts except that the weighted average shares outstanding are increased toinclude additional shares from the assumed exercise of stock options, if dilutive. The number ofadditional shares is calculated by assuming that outstanding stock options were exercised and thatthe proceeds from such exercises were used to acquire common shares at the average marketprice during the reporting period.(n) Measurement uncertainty:The amounts recorded for depletion and depreciation of petroleum and natural gas interests andthe provision for asset retirement obligation costs are based on estimates. The cost recoveryceiling test is based on estimates of proved reserves, production rates, petroleum and natural gasprices, future costs and other relevant assumptions. By their nature, these estimates are subject tomeasurement uncertainty and the effect on the consolidated financial statements of changes insuch 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 forasset retirement obligations. This standard focuses on the recognition and measurement ofliabilities related to legal obligations associated with the future retirement of property, plant andequipment. Under this standard, these obligations are initially measured at fair value determinedas the estimated future costs discounted to the present value and subsequently adjusted for theaccretion of the discount factor and any changes in the underlying cash flows. The assetretirement cost is capitalized to the related asset and amortized into earnings over time. Theeffect 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 providedfor 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 applicationof 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 costcentre exceeded its recoverable amount. The recoverable amount was the sum of theundiscounted cash flows expected from the production of proved reserves plus the lower of costor market of unproved interests less estimated future costs for administration, financing and siterestoration. 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 accountingstandard 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 toemployees and directors. The Corporation previously disclosed the pro forma effect ofaccounting for these awards under the fair value based method.The effect of adoption of the revised standard on the financial statements is disclosed innote 6(g).3. Property and equipment:2005 2004$ $Petroleum and natural gas interests and equipment ............... 73,159,179 54,514,733Drilling equipment ...................................... 2,693,618 2,055,006Building .............................................. 11,984,701 11,984,701Other ................................................ 931,289 297,69288,768,787 68,852,132Accumulated depletion and depreciation ....................... (16,385,852) (14,769,035)72,382,935 54,083,097230

A ceiling test was undertaken at December 31, 2005 to determine whether there was an impairment tocost centres with proved reserves. In undertaking the ceiling test the following forecast priceswere used:WestBukha Bukha Bukha Bukha Russia RussiaYear Brent Congo condensate Propane Butane Gas Export Domestic$/bbl $/bbl $/bbl $/tonne $/tonne $/MMBTU $/bbl $/bbl2006 ............. 55.50 54.00 56.16 360.19 370.24 1.00 50.60 29.912007 ............. 53.50 52.05 54.12 349.59 358.44 1.00 48.78 28.812008 ............. 49.50 48.16 50.05 328.39 334.84 1.00 45.13 26.632009 ............. 46.50 45.24 46.99 312.49 317.14 1.00 42.39 24.992010 ............. 45.00 43.78 45.47 304.54 308.29 1.00 41.03 24.172011 ............. 43.50 42.32 43.94 296.59 299.44 1.00 39.66 23.352012 ............. 43.50 42.32 43.94 296.59 299.44 1.00 39.66 23.352013 ............. 44.51 43.30 44.96 301.89 305.34 1.00 40.58 23.842014+ ........... +2%pa +2%pa +2%pa +2%pa +2%pa 1.00 +2%pa +2%paAt December 31, 2005, the below new cost centres were considered to be in the preproduction stageand all costs, net of revenues, were capitalized in property and equipment and excluded from costssubject to depletion and depreciation.2005 2004$ $Uganda ................................................ 26,991,887 21,342,651Russia ................................................. — 871,950Iraq .................................................. 2,785,419 836,452Democratic Republic of Congo ............................... 464,285 428,540Kazakhstan ............................................. 938,370 —Pakistan ............................................... 416,504 25,35931,596,465 23,504,952Major uncertainties affect the recoverability of these costs as the recovery of the costs outlined aboveis 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 beenexcluded from costs subject to depletion and depreciation.In 2005, the Corporation capitalized $1,332,363 (2004—$441,075) of general and administrative costsrelating to exploration and development activities.Following the acquisition of a 95% interest in the West Chumpass development license in 2005, costsin the Russian preproduction cost centre have been transferred into costs subject to depletion anddepreciation.Undeveloped lands are assessed quarterly to determine whether impairment has occurred. In thefourth quarter of 2005, the Corporation wrote-off all of the costs held in the Nigeria andTurkmenistan 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 cashconsideration of $300 and a commitment to loan up to $500,000 for NPWL’s development of theBuoyant Drum Lay System (‘‘Pipelay System’’). At December 31, 2005, NPWL and NTL, corporatejoint ventures, were proportionately consolidated in the Corporation’s financial statements assubstantially all activities are conducted jointly with others.On September 24, 2004, the Corporation acquired an additional 31.7% interest in both entities for anominal cash consideration of $285 and a commitment to loan up to an additional $170,000 for thePipelay System. Accordingly, the Corporation commenced proportionately consolidating the entitieseffective September 24, 2004. As the Pipelay System development is not complete to date, NPWL has231

no results of operations other than deferred development costs. At December 31, 2005, NTL had noassets, liabilities or operations.PreviousNet assets acquired before non controlling interest consolidation Acquired Total$ $ $Working capital ................................... 334,199 (330,708) 3,491Deferred development costs .......................... 265,803 531,608 797,411Note payable from the Corporation, without interest ........ (500,002) — (500,002)Note payable from other Shareholders ................... (100,000) (200,000) (300,000)— 900 900Non-controlling interest ............................. — (315) (315)585 585Cash consideration Acquired Total$ $Initial 33.3% interest acquired in 2003 ................................ 300 300Incremental 31.7% interest acquired in 2004 ............................ 285 285585 585At December 31, 2005, the Corporation had also directly incurred deferred development costs of$63,133. In 2005, NPWL incurred deferred development costs of $174,359.5. Asset retirement obligations:The effect of the change in accounting policy as outlined in note 2(a) has been recorded retroactivelywith restatement of prior periods. The effect of the adoption on the balance sheet and statement ofearnings is presented below as increases (decreases):Balance sheet At December 31, 2003$Asset retirement cost, included in property and equipment ............... 119,074Asset retirement obligations ..................................... 153,599Accumulated future abandonment and site restoration liability ............ (90,083)Retained earnings ............................................. 55,558The Corporation’s asset retirement obligations result from net ownership interests in petroleum andnatural gas assets including well sites and gathering systems. The Corporation estimates the totalundiscounted amount of cash flows required to settle its asset retirement obligations is approximately$695,050, which is expected to be incurred in 2010. A credit-adjusted risk-free rate of eight percentwas used to calculate the fair value of the asset retirement obligations.A reconciliation of the asset retirement obligations is provided below:2005 2004$ $Balance, beginning of year ...................................... 328,553 153,599Additions ................................................... — 82,138Revision ................................................... 80,012 80,528Accretion expense, included in depletion and depreciation ............... 26,284 12,288Balance, end of year ........................................... 434,849 328,553At December 31, 2005, estimated asset retirement obligation costs to be accreted over the remainingproved reserves were $255,202 (2004—$234,529).232

6. Share capital:(a) Authorized:Unlimited number of Common Shares without par value(b) Issued:2005 2004Number Amount Number Amount$ $Common SharesBalance, beginning of year ............ 21,454,134 21,434,168 20,991,800 20,788,253Issued on exercise of stock options (c) . . . 546,667 1,423,011 442,334 561,463Stock based compensation exercised (g) . . — 132,577 — —Issued on exercise of warrants (d) ...... — — 20,000 84,452Normal course issuer bid (e) .......... (135,100) (135,338) — —Balance, end of year ................ 21,865,701 22,854,418 21,454,134 21,434,168WarrantsBalance, beginning of year ............ 40,962Exercise 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 andconsultants of the Corporation may be granted options to purchase common shares. Under theterms of the plan, options granted normally vest one third immediately and one third in each ofthe years following the date granted and have a life of five years. In 2005, 150,000 options wereissued to non-employees at an average exercise price of Cdn$12.00 per share and a term of12 months. The cost of stock-based payments to non-employees that are fully vested andnon-forfeitable at the grant date is measured and recognized at that date.Common Share options outstanding and exercisable:Number Average Number Averageof options exercise price of options exercise price(Cdn $) (Cdn $)Balance, beginning of year .............. 476,667 1.31 919,001 1.49Granted ........................... 495,000 10.40 — —Exercised .......................... (546,667) 3.12 (442,334) 1.69Balance, end of year .................. 425,000 9.57 476,667 1.31Share capital and warrants exercisable, endof year ........................... 194,998 9.42 476,667 1.31Number of options RemainingExercise prices (Cdn $) Outstanding Exercisable Life (years)$1.35-$2.88 .................................. 30,000 30,000 1.40$9.70-$13.00 .................................. 395,000 164,998 3.90425,000 194,998 3.73233

(d) Warrants:The following outstanding Common Share warrants were issued pursuant to various privateplacements or borrowing arrangements.Number of Average Number of Averagewarrants exercise price warrants exercise price(Cdn $) (Cdn $)Balance, beginning of year ............. — — 20,000 2.80Granted .......................... — — — —Exercised ......................... — — (20,000) 2.80Balance, end of year ................. — — — —(e)Normal course issuer bids:On November 4, 2004, the Corporation renewed its normal course issuer bid to acquire up to1,069,506 Common Shares on the open market until November 3, 2005. This was replaced by anormal course issuer bid programme that commenced on November 4, 2005 and is scheduled toexpire on November 3, 2006. Pursuant to the Normal Course Issuer Bid, the Corporation maypurchase up to 1,090,785 Common Shares.Pursuant to the normal course issuer bid that expired on November 3, 2005, the Corporationacquired 135,100 Common Shares at an average price of Cdn$7.85 per share for cancellation. Nofurther acquisitions under the normal course issuer bid were made in 2005. No Common Shareswere acquired in 2004.(f)Per share amounts:The following table summarizes the weighted average common shares used in calculating netearnings per share:Weighted average common shares 2005 2004Basic .............................................. 21,650,215 21,247,565Diluted ............................................. 21,860,371 21,661,554The reconciling item between basic and diluted weighted average number of Common Shares isthe dilutive effect of stock options and warrants. A total of 150,000 options (2004—nil) and nilwarrants (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 recordedretroactively without restatement of prior periods. At January 1, 2004, the effect of the changeresulted 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)) ................. — 13,881Stock-based compensation expense ............................. 625,365 10,540Exercised ................................................ (132,577) —Balance, end of year ........................................ 517,209 24,421The 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. The234

fair value of stock options are amortized over the vesting period of the option. No stock optionswere granted in 2004.Assumptions:Risk free interest rate .............................................. 2.81%Volatility ....................................................... 58.86%Dividend yield ................................................... —Expected life (in years) ............................................. 3.80Resulting weighted average fair value (Cdn $) ............................ $ 3.937. 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 purchaserto acquire the Corporation’s overriding royalty interest in certain petroleum and natural gas interestsin the Republic of Congo for proceeds of $30,400,000 by July 30, 2004. An additional contingentconsideration of up to A 8,300,000 (approximately $10,000,000) may be payable on the sale of all or aportion of the interest by the purchaser by December 31, 2005. Concurrent with the exercise of theoption, the purchaser would be required to sell a 7% working interest in another petroleum andnatural 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 cashconsideration of $9,400,000, net of the $7,000,000 to acquire the other interest, and aEuro-denominated note receivable equivalent to $14,000,000 due on December 31, 2005 bearinginterest at Euribor plus 2.65% per annum. The net cash consideration of $9,400,000 was received inJuly 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 fullyrepaid the note receivable.The sale of the unproved interest would have changed the rate of depletion and depreciation for theRepublic of Congo by more than 20%; accordingly, a gain of $26,269,113 has been recognizedin earnings.8. Income taxes:Heritage Oil Corporation is subject to income taxes in Canada. Substantially all of the Corporation’soperating activities in 2004 and 2005 were outside of Canada in jurisdictions where the statutory taxrate is nil, since the producing assets in Oman and the Republic of Congo are subject to productionsharing 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 taxlosses of approximately $3,944,517 (2004—$3,334,846), which expire from 2006 to 2012. A valuationallowance 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 totheir 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 ofOman. In 2005 and 2004, the Corporation sold all of its production, at any point in time, in eachcountry to a single customer for each commodity. Accordingly, substantially all of theCorporation’s accounts receivables from petroleum and natural gas sales were from threecustomers.Debtors of the Corporation are subject to internal credit review to minimize the risk ofnon-payment. The Corporation does not anticipate any default as it transacts with creditworthycounterparties.2005235

(c)Foreign exchange risk:The Corporation is exposed to foreign exchange fluctuations as it holds working capital andlong-term debt in foreign currencies. In addition, a portion of the operating activities areconducted in sterling and Swiss francs. There are no exchange rate contracts in place at, orsubsequent 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 loanof $8.45 million (£4.5 million) to refinance the acquisition of a corporate office. Interest on the loan isfixed 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 by240 installments of capital and interest at monthly intervals, subject to a residual debt at the end of theterm 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 financeoffice in Switzerland that required this director to relocate and he received a relocation allowanceof $275,918.12. Commitments:Heritage’s net share of outstanding commitments at year-end 2005 are estimated at:Less thanPayments Due by Period Total 1 year 1-3 years 4-5 years After 5 yearsU.S.$m U.S.$m U.S.$m U.S.$m U.S.$mLong Term Debt .................... 7,768 248 246 246 7,028Capital Lease Obligations ............. — — — — —Operating Leases .................... 2,659 217 434 434 1,574Purchase 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 8,602The 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 ofthe properties and the individuals being unable to repay the balance. In the unlikely event this was tooccur the Corporation would look to recover any monies direct from the individual.13. Subsequent events:On March 27, 2006, the Corporation issued a $60,000,000 unsecured convertible bond, with a couponof 10% and a term of five years and one day. The bond is convertible into Common Shares at a priceof U.$.$18.00 per share at any time during the term of the bond. The Corporation may redeem thebond in whole or part at any time during the first 12 months at 150% of par value. The Corporationhas no redemption rights after the first twelve months. The proceeds of the bond can be employed fordevelopment of the West Chumpass field in Russia and for general corporate purposes.236

C. PRO FORMA FINANCIAL INFORMATION FOR THE COMPANYAccountant’s report on pro forma financial information for Heritage Oil LimitedKPMG LLP8 Salisbury Square,London, EC4Y 8BB,United KingdomThe DirectorsHeritage Oil LimitedOrdnance House31 Pier RoadSt. HelierJersey JE4 8PWChannel Islands28 March 2008Dear SirsHeritage Oil Limited (the ‘‘Company’’)We report on the pro forma financial information (the ‘‘Pro forma financial information’’) set out inPart VII(c) of the prospectus that will be dated 28 March 2008, which has been prepared on the basisdescribed in note 1, for illustrative purposes only, to provide information about how the fundraising inNovember 2007 might have affected the financial information presented on the basis of the accountingpolicies adopted by the Group in preparing the financial statements for the period ended30 September 2007. This report is required by paragraph 20.2 of Annex I of the Prospectus DirectiveRegulation and is given for the purpose of complying with that paragraph and for no other purpose.ResponsibilitiesIt is the responsibility of the directors of the Company to prepare the Pro forma financial information inaccordance 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 ProspectusDirective Regulation, as to the proper compilation of the Pro forma financial information and to reportthat opinion to you.Save for any responsibility arising under Prospectus Rule 5.5.3R (2)(f) to any person as and to the extentthere provided, to the fullest extent permitted by law we do not assume any responsibility and will notaccept any liability to any other person for any loss suffered by any such other person as a result of, arisingout of, or in connection with this report or our statement, required by and given solely for the purposes ofcomplying with paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to itsinclusion in the prospectus.Basis of OpinionWe conducted our work in accordance with the Standards for Investment Reporting issued by the AuditingPractices Board in the United Kingdom. The work that we performed for the purpose of making thisreport, 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 informationwith the directors of the Company.We planned and performed our work so as to obtain the information and explanations we considerednecessary in order to provide us with reasonable assurance that the Pro forma financial information hasbeen properly compiled on the basis stated and that such basis is consistent with the accounting policies ofthe Company.237

Our work has not been carried out in accordance with auditing or other standards and practices generallyaccepted in the United States of America or other jurisdictions and accordingly should not be relied uponas if it had been carried out in accordance with those standards and practices.OpinionIn 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.DeclarationFor the purposes of Prospectus Rule 5.5.3R (2)(f) we are responsible for this report as part of theprospectus and declare that we have taken all reasonable care to ensure that the information contained inthis report is, to the best of our knowledge, in accordance with the facts and contains no omission likely toaffect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 ofAnnex I of the Prospectus Directive Regulation.Yours faithfully(Signed) ‘‘KPMG LLP’’KPMG LLP28 March 2008238

PRO FORMA NET ASSET STATEMENTThe following pro forma net asset statement of the Group as at 30 September 2007 is prepared forillustrative purposes only and, because of its nature, addresses a hypothetical situation and therefore doesnot represent the actual financial position of the Group. It is prepared to illustrate the effect on theconsolidated balance sheet of the Group of a fund raising that the Group closed on 14 November 2007, asif the placing had taken place on 30 September 2007, and is based on the consolidated balance sheet of theGroup as at 30 September 2007 which has been extracted without material adjustment from the financialinformation set out in Part VII ‘‘Financial Information’’.Equity fundraisingadjustment Group30 September 2007 (note 2) Pro forma$ $ $(note 1) (note 2)AssetsIntangible exploration assets ................... 85,746,870 — 85,746,870Property, plant and equipment ................. 59,105,312 — 59,105,312Other financial assets ........................ 4,200,909 — 4,200,909149,053,091 — 149,053,091Current assetsInventories ............................... 79,768 — 79,768Prepaid expenses ........................... 340,402 — 340,402Trade and other receivables ................... 6,455,303 — 6,455,303Cash and cash equivalents .................... 61,894,711 176,511,326 238,406,03768,770,184 176,511,326 245,281,510217,823,275 176,511,326 394,334,601LiabilitiesCurrent liabilitiesTrade and other payables ..................... 15,781,606 — 15,781,606Borrowings ............................... 160,224 — 160,22415,941,830 — 15,941,830Non Current LiabilitiesBorrowings ............................... 144,918,765 — 144,918,765Provisions ................................ 133,274 — 133,274Derivative Financial Liability .................. 32,810,103 — 32,810,103177,862,142 — 177,862,142193,803,972 — 193,803,97224,019,303 176,511,326 200,530,629Notes:(1) The consolidated balance sheet of the Group as at 30 September 2007 has been extracted without material adjustment fromPart VII ‘‘Financial Information’’.(2) Net proceeds of the placing:Cdn$ $Placing proceeds .................................................. 181,500,000 186,436,800Placing expenses .................................................. (9,662,650) (9,925,474)Net proceeds of the Placing .......................................... 171,837,350 176,511,326The gross placing proceeds of Cdn$181,500,000 ($186,436,800) are based on 3,000,000 Common Shares being issued by theGroup pursuant to the placing each at a price of Cdn$60.50 ($62.15) per Common Share. The Group’s Common Shares have nopar 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 EarningsThe 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 beengenerated from interest earned on increased cash deposits arising from any unutilised net offer proceeds.239

PART VIII—ILLUSTRATIVE PROJECTIONS OF THE GROUPBasis of PreparationSet out below, for the purposes of illustration only, is a summary of the illustrative projected cash flows ofthe Group for the period from 1 October 2007 to 31 December 2010 (the ‘‘Illustrative Projections’’). TheIllustrative Projections have been prepared by the Directors and should be read in conjunction with theassumptions 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 requirementin paragraph 133(b)(ii) of the Committee of European Securities Regulators’ recommendations for theconsistent 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 eitherthe two years following publication of this document or, if greater, the period until the end of the first fullfinancial year in which extraction of mineral resources is expected to be conducted on a commercial scaleand for no other reason. In the absence of this requirement in the CESR recommendation, the Directorswould not have included the Illustrative Projections in this document.It is emphasised that the Illustrative Projections, which are unaudited, do not constitute any form offorecast, whether of cash, profit or otherwise. The Illustrative Projections relate to an extended futureperiod and accordingly the estimates and assumptions underlying the projections are inherently highlyuncertain 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 thenature of the Group’s business and industry which is subject to a number of significant risk factors, therecan be no assurance that the projected cash flows can be realised and it is probable that the actual cashflows will be higher or lower, possibly materially, than those projected. The attention of prospectiveinvestors 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 byunforeseen events and relate to an extended future period, the actual results reported may not correspondto those shown in the Illustrative Projections and any differences may be material.Illustrative Projections15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010$ million $ million $ millionNet cashflow (used by) from operating activities . . . (10) 5 21Taxation ................................ 0 0 0Cashflows from (used by) financing activities ..... 186 (1) (1)Capital expenditure ....................... 116 107 134Movement in cash ........................ 60 (103) (114)Opening cash balance ...................... 62 122 19Closing 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 productionprofile and the operating and capital expenditure assumptions are based on the production profile and theoperating 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 aboveIllustrative Projections.240

Production assumptionsProduction during the projected period is only assumed to arise in respect of the Bukha and West Bukhafields in Oman, together with the Zapadno Chumpasskoye field in Russia. Production as set out below isconsistent with the assumptions stated in the RPS Report in Part III of this document.15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010Boepd Boepd BoepdOman:Bukha ................................. 126 — —West Bukha ............................. 375 1,560 1,878Russia:Zapadno Chumpasskoye .................... 1,110 2,198 4,275Production is expected to commence from the West Bukha field in the third quarter of 2008 with salescommencing in the same period. It is assumed that production from the Bukha field will cease when WestBukha commences production.The Directors have assumed that all the production licences are and will remain valid over the period ofthe Illustrative Projections.No additional production is assumed to arise from projects and activities which form part of the Group’slong-term strategic plans and intentions, but which are not reflected in the report prepared by RPS inPart III of this document. Production has only been included from projects which have proved andprobable reserves certified by RPS at 30 September 2007.Price assumptionsThe 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 thisdocument.15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010Oman:Condensate, $/bbl ......................... 84 85 87LPG, $/tonn ............................. 542 547 555Gas, $/mcf .............................. 1 1 1Russia:Crude oil, $/bbl .......................... 55 53 51Cost assumptionsAn overview of the operating and capital expenditures has been given below. These expenditures havebeen estimated in accordance with the long-term strategic plans of the Group at the date of this document,as reflected in the report prepared by RPS in Part III of this document.Operating costs15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010$ million $ million $ millionOman:Bukha ................................. 1.0 — —West Bukha ............................. 0.3 0.9 1.1Russia:Zapadno Chumpasskoye .................... 7.8 9.9 12.6241

Capital expenditure15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010$ million $ million $ millionOman — West Bukha ...................... 15.8 — 12.5Uganda ................................ 18.5 3.8 3.8Russia ................................. 43.2 85.4 84.7Pakistan ................................ 1.0 1.0 1.0KRI................................... 27.0 8.0 0.5Malta .................................. 5.9 0.4 22.8Mali .................................. 4.8 8.8 8.3116.2 107.4 133.6There 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 PSCsand licences.No additional capital expenditure is assumed to arise in relation to projects and activities that the Group isconsidering undertaking, but which are not reflected in the report prepared by RPS in Part III of thisdocument, 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.TaxationIncome tax has been estimated in accordance with the applicable tax regimes and taking into considerationavailable losses and allowances in which the Group operates.Financing assumptions15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010$ million $ million $ millionRepayment of Begal loan ................... 0.6 0.5 0.5Repayment of Coatbridge loan ............... 0.2 0.2 0.20.8 0.7 0.7At a future date twelve months from the date of this document, the Group will be seeking additional equityand/or debt financing round(s) or could consider selling non-core assets during the period of theIllustrative Projections to finance the remainder of the operational expenditures required to bring theinitiated oil and gas development exploration activities into full production and fund explorationprogrammes. For the purposes of the Illustrative Projections only, it is assumed to be equity finance. Theextent to which debt might be raised at a future time is not included within the Illustrative Projections andwould create additional interest and capital repayments for the Group.242

Macroeconomic assumptionsThe Directors have assumed the following:Foreign exchange ratesThere will be no material fluctuations in respect of foreign exchange rates. The following exchange rateshave been adopted throughout the projected period:15 months ending 12 months ending 12 months ending31 December 2008 31 December 2009 31 December 2010RR/US$ ................................ 25 25 25US$/£ ................................. 1.9973 1.9973 1.9973CHF/US$ ............................... 1.20 1.20 1.20Cdn$/US$ .............................. 0.98 0.98 0.98InflationAnnual inflation will be 2 per cent. for operating expenses and 20 per cent. for general and administrativeexpenses throughout the forecast period.InterestLIBOR will be 3 per cent. throughout the forecast period.Commercial termsThe 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 assumptionsThe Directors have assumed: There will be no changes in applicable legislation, taxation, regulations, political or economicconditions 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 orits operations and customers; and For the purpose of the Illustrative Projections, it has been assumed that the Group will not make anymajor acquisitions or disposals, although such acquisitions or disposals may in fact occur.Risk factorsThe Illustrative Projections are subject to a variety of material risk factors that could cause the actual cashflows to differ materially from those projected. The most significant risk factors impacting these IllustrativeProjections 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 mayneed, after 12 months from the date of this document, in certain circumstances to obtain further debt orequity financing.243

Accountant’s report on the illustrative cash flow projectionsThe following is the full text of a report on the Illustrative Projections of the Company from KPMG LLPas reporting accountants:KPMG LLP8 Salisbury Square,London, EC4Y 8BB,United KingdomThe DirectorsHeritage Oil LimitedOrdnance House31 Pier RoadSt. HelierJersey JE4 8PWChannel Islands28 March 2008Dear SirsHeritage Oil LimitedWe report on the illustrative cash flow projections of Heritage Oil Limited (‘‘the Company’’) and itssubsidiaries (‘the Group’) for the two year period ending 31 December 2010 (the ‘‘IllustrativeProjections’’). The Illustrative Projections, and the material assumptions upon which they are based, areset out on pages 240-243 of the prospectus (the ‘‘Prospectus’’) issued by the Company and will be dated28 March 2008.The Illustrative Projections have been prepared by the directors of the Company, for illustrative purposesonly, in order to show a possible outcome and they should be read in conjunction with the assumptions andbasis of preparation accompanying them. The Illustrative Projections have been presented solely for thepurposes of complying with the Committee of European Securities Regulators (‘‘CESR’’)recommendations for the consistent implementation of the European Commission’s Regulations onProspectuses No.809/2004 (the ‘‘CESR recommendations’’), paragraph 133. This report is required byparagraph 133(b)(iii) of the CESR recommendations and is given for the purpose of complying with thatparagraph and for no other purpose.ResponsibilitiesIt is the responsibility of the directors of the Company to prepare the Illustrative Projections in accordancewith 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 CESRrecommendations, as to whether the Illustrative Projections have been stated after due care and enquiryand 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 toany other person for any loss suffered by any such other person as a result of, arising out of, or inconnection with this report or our statement, required by and given solely for the purposes of complyingwith paragraph 23.1 of Annex I of the Prospectus Directive Regulation, consenting to its inclusion inthe Prospectus.Basis of preparation of the Illustrative ProjectionsThe 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 statedassumptions. The length of the period covered by the Illustrative Projections, means that the outcomebased 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 orotherwise. The Illustrative Projections relate to an extended future period and accordingly the estimatesand assumptions underlying the projections are inherently uncertain, based on events that have not takenplace, and are subject to significant economic, competitive and other uncertainties and contingenciesbeyond the Group’s control. Further, given the nature of the Group’s business and industry which issubject to a number of significant risk factors, there can be no assurance that the projected cash flows canbe realised. Since the Illustrative Projections relate to the future actual cash flows are likely to differ fromthose projected because events and circumstances frequently do not occur as expected and the differencemay be material. Attention is drawn to the ‘‘Risk Factors’’ section of the Prospectus.Basis of opinionWe conducted our work in accordance with the Standards for Investment Reporting issued by the AuditingPractices Board in the United Kingdom to the extent that such standards are applicable in respect of thiswork. Our work included discussing with the directors of the Company the processes undertaken by themin identifying the key matters, risks and assumptions affecting cash flows and in compiling the IllustrativeProjections based upon the disclosed assumptions. The assumptions upon which the Illustrative Projectionsare 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 considerednecessary in order to provide us with reasonable assurance that the Illustrative Projections have beenstated 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 maytherefore be affected by unforeseen events, we can express no opinion as to whether the outcome shown inthe Illustrative Projections will correspond with actual results to be reported and the differences maybe material.Our work has not been carried out in accordance with auditing or other standards and practices generallyaccepted in the United States of America or other jurisdictions and accordingly should not be relied uponas if it had been carried out in accordance with those standards and practices.OpinionIn our opinion the Illustrative Projections have been stated by the Company after due care and enquiry.DeclarationFor the purposes of Prospectus Rule 5.5.3R(2)(f) we are responsible for this report as part of theprospectus and declare that we have taken all reasonable care to ensure that the information contained inthis report is, to the best of our knowledge, in accordance with the facts and contains no omissions likely toaffect its import. This declaration is included in the prospectus in compliance with paragraph 1.2 ofAnnex 1 of the Prospectus Directive Regulation.Yours faithfully(Signed) ‘‘KPMG LLP’’KPMG LLP28 March 2008245

PART IX—CORPORATE REORGANISATION1. GROUP CAPITAL RE-ORGANISATIONCompany StructureIn anticipation of Admission, HOC has proposed a reorganisation which will be completed by way ofthe Plan of Arrangement shortly before Admission. Pursuant to the Plan of Arrangement, each holderof HOC Common Shares will exchange their shares for Ordinary Shares or Exchangeable Shares on aone-for-ten basis. Exchangeable Shares have certain special rights described below including the rightto direct the Trustee as to how it should exercise a number (equal to the number of ExchangeableShares held) of the votes attaching to the Special Voting Share issued by the Company for thesepurposes. The option to elect for Exchangeable Shares has been granted by the Company in order toallow Canadian holders of HOC Common Shares to participate in the future performance of theCompany in a tax efficient manner by continuing to hold Canadian securities or interests. TheExchangeable Shares are to be admitted to listing on the TSX and the Official List and to trading onthe LSE’s main market for listed securities.Immediately following Admission, there will be 4,431,120 Exchangeable Shares issued andoutstanding in HOC. Additionally, pursuant to the Plan of Arrangement, there will be24,545,340 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 itsoption, either (a) the Company is substituted under the bonds as principal debtor in place of HOC orbecomes a guarantor under the bonds and, in either case, to make necessary consequentialamendments such that the bonds may be converted into or exchanged for Ordinary Shares; or (b) suchamendments are made to the bonds such that the bonds may be converted into or exchanged forOrdinary Shares. Accordingly, at or immediately prior to Admission the terms and conditions of theHOC Bonds will be amended such that the holders of the HOC Bonds will be entitled to convert theirbonds 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 ofthe Company) will own 100 per cent. of the share capital of Alberta CallCo which will in turn own100 per cent. of the HOC Common Shares. As a result, HOC will be controlled by the Company byvirtue of its indirect 100 per cent. membership in DutchCo.The corporate structure immediately subsequent to completion of the Plan of Arrangement will beas follows.Non-Residents and Non-ElectingCanadian ResidentsOrdinarySharesThe Company(Jersey)Voting andExchangeTrustSpecial Voting ShareJersey Subco(Jersey)DutchCo(Netherlands)HOC CommonSharesAlberta CallCo(Alberta)HOC(Alberta)Electing Canadian ResidentsExchangeableShares12MAR200802413099246

Arrangement AgreementPursuant to the Arrangement Agreement, Canadian resident holders of HOC Common Shares whoelect to do so will receive ten Exchangeable Shares for each HOC Common Share held. Canadianresident holders of HOC Common Shares who do not elect to receive Exchangeable Shares willreceive ten Ordinary Shares for each HOC Common Share held. Non-residents of Canada will receiveten Ordinary Shares for each HOC Common Share held. Holders of HOC Common Shares whodissent to the Plan of Arrangement will be entitled to receive cash proceeds equal to the fair marketvalue of their HOC Common Shares. Finally, holders of HOC Options will receive ten Options foreach HOC Option held, and the exercise prices of such options will be divided by a factor of ten andconverted into pounds sterling of the United Kingdom.A special meeting of Heritage Securityholders was held on 20 March 2008 at which HeritageSecurityholders entitled to vote in respect of the Plan of Arrangement passed a resolution approvingthe Plan of Arrangement which required the affirmative vote of 66 2 ⁄3 per cent. of votes cast by holdersof HOC Common Shares as well as by Heritage Securityholders present in person or representedby proxy.Following receipt of the approval of Heritage Securityholders, HOC has received from the Court ofQueen’s Bench (Alberta) a final order approving the Plan of Arrangement. The Plan of Arrangementwill become effective upon the Effective Date.The obligation of the parties to complete the Plan of Arrangement is subject to a number ofconditions, including, but not limited to, the regulatory approvals and not more than 3 per cent. ofholders 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 anytime prior to the Effective Date.2. RIGHTS OF EXCHANGEABLE SHAREHOLDERSGeneralExchangeable Shareholders will have certain economic rights, and Voting Rights in the managementof the Company, pursuant to the Support Agreement, the Exchangeable Share provisions and theVoting and Exchange Trust Agreement as more fully described below and in section 6.3 of Part X ofthis document.Under the Exchangeable Share provisions, so long as Exchangeable Shares are outstanding, theCompany covenants to the fullest extent permitted by law not to declare or pay any dividend on theOrdinary Shares unless: (i) HOC shall simultaneously declare or pay, as the case may be, anequivalent dividend on the Exchangeable Shares; and (ii) HOC shall have sufficient money or otherassets or authorised but unissued securities available to enable the due declaration and the due andpunctual payment, in accordance with applicable law, of any such dividend on the ExchangeableShares. 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 ExchangeableShareholders are entitled to receive the economic equivalent for each Exchangeable Sharefrom HOC.In addition, under the Support Agreement the Company has agreed to ensure that HOC will be in aposition to make all necessary payments in the event of the liquidation, dissolution or winding-up ofHOC, 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 necessarypayments in the event it exercises its right to acquire any Exchangeable Shares where a holder ofExchangeable Shares has given a redemption notice to HOC and in certain other circumstances.Exchange RightsSubject to certain conditions, each Exchangeable Shareholder has the right to exchange all or any ofits Exchangeable Shares for Ordinary Shares on a one-to-one basis, upon written request of suchExchangeable Shareholder. Notwithstanding the foregoing, holders of the Exchangeable Shares whoare persons or entities in the United States of America or are a ‘‘US Person’’ within the meaning ofRegulation 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. ofthe actual number of Exchangeable Shares issued remain outstanding, HOC will be entitled to redeemall but not less than all of the remaining outstanding Exchangeable Shares. HOC will deliver to eachholder of Exchangeable Shares one Ordinary Share for each Exchangeable Share redeemed, togetherwith any declared and unpaid dividends on the redeemed shares.Rights of Alberta CallCo Holding in HOCImmediately subsequent to completion of the Plan of Arrangement, Alberta CallCo will hold directly100 per cent. of the HOC Common Shares.Voting RightsThe holders of Exchangeable Shares are entitled to Voting Rights and through the Special VotingShare held by the Trustee will have the right to direct the Trustee how to vote at general meetings ofthe Company (on the basis of one vote for every Exchangeable Share) but not at any class meeting ofthe holder of the Special Voting Share. In addition, where the Company, inter alia, seeks to issueadditional Ordinary Shares, is subject to a takeover offer, or reorganises its share capital, theCompany will seek to put the holders of Exchangeable Shares in a similar position to the holders ofOrdinary Shares.The principal rights attaching to the Exchangeable Shares and the Voting Rights attaching to theSpecial Voting Share held by the Trustee for the benefit of holders of Exchangeable Shares aregranted under the terms of the Articles, the Exchangeable Share provisions, the Voting and ExchangeTrust Agreement and/or the Support Agreement.DividendsUnder the Support Agreement, the Company agreed not to pay a cash dividend to holders ofOrdinary Shares unless a cash dividend in the same amount has been declared on all theExchangeable Shares. Should the Board decide to pay a share dividend or a dividend declared inproperty to holders of Ordinary Shares, each holder of Exchangeable Shares would be entitled toreceive the economic equivalent of such dividend on their Exchangeable Shares from HOC.Liquidation, Dissolution and Winding-UpUpon liquidation, dissolution or winding-up of HOC or distribution of assets of HOC for the windingupof its affairs, the holders of Exchangeable Shares will receive in preference to the other classes ofshares 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 remainingproperty of HOC.248

PART X—ADDITIONAL INFORMATION1. RESPONSIBILITY1.1 The Company and its Directors (whose names appear on page 27 of this document) acceptresponsibility for the information contained in this document. To the best of the knowledge of theCompany and the Directors (who have taken all reasonable care to ensure that such is the case), theinformation contained in this document is in accordance with the facts and contains no omissionlikely to affect its import.2. INCORPORATION2.1 The Company was incorporated on 6 February 2008 in Jersey under the Act, as a company limitedby shares with the name Heritage Oil Limited and registered number 99922. The Company has nocommercial 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 assumingcompletion 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 regulationsthereunder.3. SUBSIDIARIES3.1 Upon Admission, the Company has the following significant subsidiary undertakings all of whichare, save as described below, private limited companies, wholly owned, and incorporated in thejurisdictions specified below.Ownership Jurisdiction ofName/Date of Incorporation Registered Office Interest IncorporationHeritage Oil Corporation #260 Petex Building 100 per cent. Alberta, Canada(incorporated on600 - 6th Avenue SW30 October 1996) Calgary, AlbertaT2P 0S5Heritage Oil & Gas Limited Suite E2, Union Court Building 100 per cent. Commonwealth of(incorporated on Elizabeth Avenue and Shirley the Bahamas14 January 1992) Street, Nassau, BahamasEagle Energy (Oman) Limited Castle Hill, Victoria Road, 100 per cent. Isle of Man(incorporated on 22 July 1992) Douglas, Isle of Man, IM2 4RBHeritage Energy Middle East P.O.Box 693, Hamilton Estate, 100 per cent. Island of NevisLimited (incorporated on Charlestown, Nevis8 January 2007)Heritage DRC Limited P.O.Box 693, Hamilton Estate, 100 per cent. Island of Nevis(incorporated onCharlestown, Nevis17 December 2002)Coatbridge Estates Limited Akara Building, 24 De Castro 100 per cent. British Virgin Islands(incorporated onStreet, Wickhams Cay, Road24 September 2004) Town, Tortola, British VirginIslands.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 ofName/Date of Incorporation Registered Office Interest IncorporationNeftyanaya Geologicheskaya ul. Samotlornaya 20, 99 per cent. Russian FederationKompaniya (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 onCharlestown, Nevis17 October 2007)Heritage Mali Block 11 Limited P.O. Box 693, Hamilton Estate, 50 per cent. Island of Nevis(incorporated onCharlestown, Nevis17 October 2007)Heritage Oil International Malta Akara Building, 24 de Castro 100 per cent. British Virgin IslandsLimited (incorporated on Street, Wickhams Cay, Road22 November 2007) Town, Tortola, British VirginIslandsBegal Air Limited, (incorporated Castle Hill, Victoria Road, 100 per cent. Isle of Man9 October 2006) Douglas, Isle of Man, IM2 4RBTISE-Heritage Neftegaz 1 st Brestskaya St. 15, 50 per cent. Russia(incorporated 27 June 2007) 125047 Moscow4. SHARE CAPITAL4.1 Share Capital of the Company(a) As at the date of incorporation of the Company, the authorised and issued share capital of theCompany was as follows:AuthorisedIssuedNumber Amount Number AmountUnlimited number of No par value 1 Ordinary Share No par valueOrdinary Shares(b) The authorised share capital of the Company as at the date of this document is unlimited. TheCompany is authorised to issue shares with no par value designated as Ordinary Shares and aSpecial Voting Share. At the date of this document there are two Ordinary Shares in issue andone Special Voting Share in issue.(c) The authorised and issued fully paid up share capital of the Company as it is expected to beimmediately following Admission is:AuthorisedIssuedNumber Amount Number AmountUnlimited number of No par value 250,513,032 Ordinary Shares No par valueOrdinary Shares1 Special Voting No par value 1 Special Voting Share No par valueShare(d) Upon Admission, the Company will have 24,545,340 Options outstanding, and HOC will have4,431,120 Exchangeable Shares outstanding, each of which will entitle the holder thereof toexchange each such Exchangeable Share or Option for one Ordinary Share, further details ofwhich 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 sharecapital of the Company or HOC and neither the Company nor HOC has given anyundertaking to increase its share capital;250

(ii) no share or loan capital of the Company or HOC (or any of their subsidiaries) is underoption or is the subject of an agreement, conditional or unconditional, to be put underoption and there is no current intention to issue any of the authorised and unissuedOrdinary Shares;(iii) there are no arrangements currently in force for involving the employees in the capital ofthe Company or HOC; and(iv) neither the Company nor HOC has any convertible securities, exchangeable securities orsecurities 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 subsidiaryof the Company.(h) None of the Directors nor members of their families has a related financial product referencedto the Ordinary Shares, other than Exchangeable Shares as disclosed in sections 1 and 2 ofPart IX.(i) The ISIN (International Security Identification Number) to be used in relation to the OrdinaryShares 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 beingheld in uncertificated form, enabled through CREST. Further details of the operation of theCREST system are set out in Part I of this document. Definitive share certificates for offereesnot settling through CREST are planned to be dispatched in the week commencing7 April 2008. No temporary documents of title will be issued. Prior to the dispatch of suchcertificates, transfers will be certified against the Company’s register.(l) On 25 February 2008 and 18 March 2008, respectively, the existing shareholders of theCompany 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 publiccompany; 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 theOrdinary Shares.(n) Under articles 117 and 118 of the Act, an offeror in respect of a takeover offer which does notrelate to shares of different classes, has the right to acquire shares to which the offer relates butwhich he has not acquired or contracted to acquire where he has acquired or is contracted toacquire not less than nine-tenths in number in the case of no par value companies of the sharesto which the offer relates. The offeror may not issue a notice requiring the acquisition ofminority shares unless he has acquired or contracted to acquire not less than nine-tenths innumber of the shares to which the offer relates before the end of four months beginning withthe date of the offer and no notice may be given after the end of the period of two monthsbeginning with the date on which the offeror has acquired or contracted to acquire not lessthan nine-tenths in number. The squeeze out of minority shareholders can be completed at theend of 6 weeks from the date of the notice requiring the squeeze out. By virtue of article 119 ofthe Act, minority shareholders in respect of a takeover offer can require the offeror to acquiretheir shares provided the offeror has, before the end of the period within which the offer canbe accepted, acquired or contracted to acquire not less than nine-tenths in number in the caseof no par value companies of all the shares in the Company. Unless the offeror has given noticeunder article 117 of the Act, an offeror shall within one month of the end of the period withinwhich the offer can be accepted give the remaining shareholders notice of their rights torequire the offeror to acquire their shares. The notice may specify a period for the exercise ofthe remaining shareholders’ rights to be bought out, but that period must be at least 3 monthsafter 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 rightto acquire shares to which the offer relates but which he has not acquired or contracted to251

acquire where he has acquired or is contracted to acquire not less than nine-tenths in numberof any class in the case of no par value companies of the shares to which the offer relates. Theofferor may not issue a notice requiring the acquisition of minority shares unless he hasacquired or contracted to acquire not less than nine-tenths in number of any class of the sharesto which the offer relates before the end of four months beginning with the date of the offerand no notice may be given after the end of the period of two months beginning with the dateon which the offeror has acquired or contracted to acquire not less than nine-tenths in numberof any class. The squeeze out of minority shareholders can be completed at the end of 6 weeksfrom 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 theirshares provided the offeror has, before the end of the period within which the offer can beaccepted, acquired or contracted to acquire not less than nine-tenths in number of any class inthe case of no par value companies of all the shares in the Company. Unless the offeror hasgiven notice under article 117 of the Act, an offeror shall within one month of the end of theperiod within which the offer can be accepted give the remaining shareholders notice of theirrights to require the offeror to acquire their shares. The notice may specify a period for theexercise of the remaining shareholders’ rights to be bought out, but that period must be at least3 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 Sharessince 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:AuthorisedIssuedNumber Amount Number AmountUnlimited HOC Common No par value Nil HOC Common Shares No par valueSharesUnlimited Exchangeable No par value 4,431,120 Exchangeable No par valueSharesShares(c) The ISIN (International Security Identification Number) to be used in relation to theExchangeable 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 capableof being held in uncertificated form. The directors of HOC will make arrangementsimmediately after Admission for trades in the Exchangeable Shares to be settled throughCREST via depository interests representing the Exchangeable Shares for those Shareholderswho wish to hold their Exchangeable Shares in electronic form. Definitive share certificates forofferees not settling through CREST are planned to be dispatched in the week commencing7 April 2008. No temporary documents of title will be issued. Prior to the dispatch of suchcertificates, 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 ofArrangement providing for, in effect, the exchange of all the issued and outstanding HOCCommon Shares for Ordinary Shares or Exchangeable Shares.(h) Save as summarised in this Part X, there are no restrictions on the free transferability of theExchangeable Shares.(i) HOC exists under the laws of the Province of Alberta, Canada and accordingly, transactions inthe Exchangeable Shares will not be subject to the provisions of the City Code. Instead, untilsuch time that HOC ceases to be a ‘‘reporting issuer’’ (as defined under applicable securitieslaws), HOC will remain subject to applicable Canadian securities laws.In Canada, securities laws are generally a matter of provincial/territorial jurisdiction and as aresult, takeover bids are governed by the securities legislation in each province or territory.252

(j)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’’), exceptpursuant to a formal bid, acquires beneficial ownership of, or the power to exercise control ordiscretion over, or securities convertible into, voting or equity securities or any class of areporting issuer that, together with such offeror’s securities would constitute 10 per cent. ormore of the outstanding securities of that class, the offeror must immediately issue and file apress release announcing the acquisition, and file a report of such acquisition with theapplicable securities regulatory authorities within two business days thereafter. Certaininstitutional investors may elect an alternate reporting system. Once an offeror has filed suchreport, the offeror is required to issue further press releases and file further reports each timethe offeror, or any person acting jointly or in concert with the offeror, acquires beneficialownership 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 orequity securities of a class made to any holder in Alberta of securities subject to the offer toacquire, if the securities subject to the offer to acquire, together with securities held by theofferor and any person acting in concert with the offeror, constitute in aggregate 20 per cent. ormore 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 theclass that is subject to the bid who are in Alberta and must allow such security holders 35 daysto deposit securities pursuant to the bid. The offeror must deliver to the security holders atakeover bid circular which describes the terms of the takeover bid and the directors of thereporting 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 forthe recommendation or a statement that the directors are unable to make or are not making arecommendation and the reasons why. Generally, an offeror may not enter into a collateralagreement, understanding or commitment that has the effect of providing a security holderwith 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 thatprovince, the Canadian Securities Administrators have adopted a policy whereby they mayissue a cease trade order against a company if a takeover bid is not made to all Canadiansecurity holders. Shareholders not resident in Canada are advised that the provincial securitieslaws in Canada may not apply in foreign jurisdictions. Accordingly, the availability of atakeover bid to Shareholders residing outside of Canada will be dependent on whether suchtakeover bid may be made to such non-Canadian Shareholders pursuant to applicablelegislation of the jurisdiction in which the non-Canadian shareholder resides and the actions ofthe acquiring company.Under Alberta corporate law, where an offeror has successfully acquired 90 per cent. of theshares of a company (exclusive of those previously held by the offeror), the offeror may, withinfour months after making the offer to acquire shares of the company, send written notice toany shareholder who did not accept the offer compelling them to sell their shares on the sameterms as contained in the original offer, subject to the right of such shareholder to makeapplication to court, in which case the court may set the price and terms of payment and makesuch other consequential orders and give such directions as it deems appropriate.There have been no public takeover bids by third parties in respect of the Exchangeable Sharessince HOC’s last financial year and the current financial year.5. JERSEY COMPANY LAWThere are a number of material differences between the Companies Act and the Act which mayimpact upon the rights of holders of Ordinary Shares. Salient differences include (withoutlimitation) the following:(a) the Act does not confer statutory pre-emption rights on shareholders relating to newshare issues. But the Articles do confer pre-emption rights on shareholders relating to newissues of Ordinary Shares;(b) the Act does not impose any requirement for the directors to obtain the sanction of theshareholders to issue and allot shares. But the Articles do impose restrictions on amounts that253

may be allotted annually, such amounts being subject to approval by the shareholders in ageneral meeting;(c) the Act permits the incorporation of companies with no par value shares and the holding by aCompany 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 paidup 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 generalmeeting of the company where the net assets of the company are half or less of its called-upshare capital;(f) there is no requirement under the Act for a company to have a minimum authorisedshare 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 isrequired to be passed by two-thirds of shareholders present (in person or by proxy) at therelevant meeting and this two-thirds threshold cannot be increased;(i) the circumstances in which the Act permits a Jersey company to indemnify its directors inrespect of liabilities incurred by the directors in carrying out their duties are limited, albeit in aslightly different manner to English companies. In particular, there is no express right for aJersey 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 theirbeneficial ownership of any shares in the company (although they must disclose to the companythe nature and extent of any direct or indirect interest in a transaction entered into orproposed to be entered into by the company or by any subsidiary of the company which, to amaterial extent, conflicts with, or may conflict with, the interests of the company and of whichsuch director is aware). Similarly, the Act does not grant the directors of a Jersey company astatutory power to request information concerning the beneficial ownership of shares. But theArticles 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 theshareholders of a company who have the right to vote at the meeting requisitioned mayrequisition a meeting of shareholders;(l) contrary to the position under the Companies Act and the New Companies Act where directorsmust disclose any interest they may have in a contract to be entered into by the company or bya subsidiary of the company, the director of a Jersey company need only make a disclosurewhere his interest materially conflicts with that of the company and of which such directoris aware. But the Articles do restrict the directors’ ability to vote or count in the quorum inrelation to such contracts of arrangements;(m) the Act does not contain a provision which would require prior shareholder approval oftransactions with directors of the company. But the Articles do require the shareholders toapprove any loans, quasi-loans or credit transactions granted or guaranteed by the Company toany of the directors or their connected persons, so long as the aggregate nominal amount ofsuch 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 directordoes not exceed an aggregate nominal amount of £50,000. There are further exceptionscontained within the Articles;(n) the Act does not confer power on the shareholders to remove directors from office and anysuch power has to be expressly provided for in the articles of the Jersey company. The Articlesdo 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 questionby: (i) not less than five shareholders having the right to vote on the question; or (ii) ashareholder or shareholders representing not less than one-tenth of the total voting rights of allshareholders having the right to vote on the question. The Articles also provide that a poll maybe demanded by (i) a member or members holding a right to vote on which an aggregate254

nominal amount has been paid up of not less than one-tenth of the total sum paid up on allshares 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 ofa company on the company’s website and no power is conferred upon the shareholders torequire an independent report on a poll. The Articles do however confer these requirementsand powers;(q) there is no requirement under the Act that annual accounts and reports and preliminarystatements of listed companies be posted on a website, nor is there a requirement thatshareholders’ concerns about an audit of the company’s annual accounts be published on thecompany’s website. The Articles do however include a requirement that the annual accountsand 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 (whichunder the New Companies Act would need to contain information about environmentalmatters, employees, social and community issues and persons with whom the company hascontractual or other arrangements which are essential to the business). The Articles dohowever 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 ofemployees of the company in connection with the cessation or transfer of the undertaking ofthe company;(u) while under the Act the directors of a Jersey company are required to act honestly and in goodfaith with a view to the best interests of the company and to exercise the care, diligence andskill that a reasonably prudent person would exercise in comparable circumstances, under theNew Companies Act a director, while promoting the success of the company, is also required tohave regard to the interests of the company’s employees, and to the need to foster businessrelationships with suppliers and customers and the impact of the company’s operations on theenvironment; and(v) under Jersey law, the two principal procedures for dissolving a Jersey company are winding-upand désastre. The concept of a winding up is broadly similar to that under English law, exceptthat under Jersey law, a winding-up may only be commenced by the Jersey company and not byone of its creditors. If the company is solvent the winding up will be a summary winding-up. Ifthe company is insolvent, the winding-up will be a creditors’ winding-up. A creditor wishing todissolve a Jersey company would seek to have the company’s property declared en désastreunder the Bankruptcy (Désastre) (Jersey) Law 1990, as amended. If the company’s property isdeclared en désastre, all of the powers and property of the company (belonging to or vested inthe company at the date of the declaration and all powers in or over or in respect of suchproperty exercisable by the company at the date of the declaration and whether situated inJersey or elsewhere) are vested in the Viscount (an officer of the court). The role of theViscount is similar to that of a liquidator. The Viscount’s principal duty is to distribute theassets of the company among the persons entitled to receive them in accordance with theirrespective 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 constitutelegal advice. Any Shareholders wishing to obtain further information regarding their rights as ashareholder under Jersey law should consult their Jersey legal advisers.6. MEMORANDUM AND ARTICLES OF ASSOCIATION OF THE COMPANY/ARTICLES OF HOC6.1 Memorandum of Association of the CompanyThe Memorandum is available for inspection at the address specified in section 19 below. Underthe Act, the capacity of a Jersey company is not limited by anything contained in its memorandum255

or articles of association or by any act of its members. Accordingly, the Memorandum does notcontain an objects clause.6.2 Articles of the CompanyThe Articles have been adopted and include provisions to the following effect:(a) Alteration of share capitalThe Company may by special resolution alter its share capital in any manner permitted by theAct. Subject to the provisions of the Act, the Company may by special resolution reduce itsstated capital accounts or other undistributable reserve in any way.(b) Purchase of own sharesSubject to the Act the Company may purchase any of its own shares of any class, including anyredeemable shares, provided that if there are in issue any shares which are admitted to theOfficial List and which are convertible into equity share capital of the Company of the classproposed to be purchased, the Company may not purchase or enter into a contract underwhich it will or may purchase such shares unless either the terms of issue of the convertibleshares include provisions permitting the Company to purchase its own shares or provide foradjustment of the conversion terms upon such a purchase or the purchase or contract is firstapproved by special resolution of the holders of such convertible shares.(c) Share rightsWithout prejudice to any special rights attached to any existing shares or class of shares, anyshare in the Company may be issued with such preferred, deferred or other special rights orrestrictions as the Company may by special resolution determine.Subject to the Act the Company may issue or convert any existing non-redeemable shares onsuch terms and in such manner as may be determined by Special Resolution into shares whichare, or at the option of the Company or the holder are liable, to be redeemed.(d) Derivative ClaimsExcept in relation to acts or omissions authorised or ratified by the Company in generalmeetings, 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 inrespect of a cause of action vested in the Company with a view to obtaining relief on behalf ofthe Company, provided such proceedings are only in respect of a cause of action arising froman actual or proposed act or omission involving negligence, default, breach of duty or breach oftrust by any Director, and may at any stage apply to the Court for leave to continue or takeover the conduct of proceedings issued by the Company or by another member by way ofderivative action if the manner in which the Company or the other member commenced orcontinued the proceedings amounts to an abuse of process of Court, or if either of them failedto prosecute the claim diligently or it is in all the circumstances more appropriate for themember to continue the proceedings as a derivative action.(e) Allotment of securities and pre-emption rightsSubject to the provisions of the Act and any resolution of the Company passed in a generalmeeting, all unissued shares are at the disposal of the Directors and they may allot, grantoptions over or otherwise dispose of them to persons at such times and on such terms as theythink proper provided that, although the Act does not provide any statutory pre-emptionrights, 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 beenindependently valued.(f) Share certificatesEvery holder of shares in certificated form whose name is entered on the Company’s register ofmembers is entitled without payment to a certificate in respect of such shares within one monthafter allotment or within five business days (in the case of a transfer of fully-paid shares) afterthe lodgement of the instrument of transfer or within two months of the lodgement of the256

instrument of transfer (in the case of a transfer of partly-paid shares). In the case of jointholders, delivery of a certificate to one of the joint holders shall be sufficient delivery to all.(g) Forfeiture and lienThe Directors may from time to time make calls upon the members in respect of any moniesunpaid 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 placeof payment) pay to the Company the specified amount called on his shares. If a member fails topay in full any call or instalment of a call on or before the due date for payment, the Directorsmay at any time thereafter serve a notice in writing to him requiring payment of such unpaidamount together with any interest accrued thereon and any expenses incurred by the Companyby reason of such non-payment. Interest shall accrue on any sums which are unpaid from theday appointed for payment thereof to the time of actual payment at such rate as the Directorsmay determine (although this shall not exceed 15 per cent. per annum). The notice shall statethat in the event of non-payment in accordance with the notice, the shares on which the call hasbeen made will be liable to be forfeited. The Company shall have a first and paramount lien onevery 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 asthe Directors think fit, any share on which the Company has a lien if any sum in respect ofwhich the lien exists is presently payable and is not paid within 14 days after a notice ofintention to sell the share in default of payment shall have been given to the holder ofthe share.(h) Variation of rights(i) Subject to the provisions of the Act, the special rights attached to the Ordinary Shares maybe varied or abrogated either with the written consent of the holders of two-thirds ofissued Ordinary Shares or the sanction of a special resolution passed at a separate meetingof the holders of the Ordinary Shares.(ii) The special rights attached to the Special Voting Share may, subject to the provisions ofthe Act, be varied or abrogated with the sanction of a resolution passed at a separatemeeting of the holder of the Special Voting Share by a majority of not less than two-thirdsof the aggregate number of voting rights attaching to the Special Voting Share on a polland which are exercised at such meeting (but not otherwise) and may be so varied orabrogated either whilst the Company is a going concern or during or in contemplation of awinding-up. To every such meeting the provisions of the Articles relating to generalmeetings and to the proceedings thereat shall mutatis mutandis apply, except that thenecessary quorum shall be one person at least holding or representing by proxy at leastone-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 inperson or by proxy shall be a quorum) and that all resolutions put to the vote at any suchmeeting 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 transferin 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 theshare is fully paid, by or on behalf of the transferee. An instrument of transfer may beunder hand only.(ii) All transfers of shares which are in uncertificated form shall, subject to the Regulations, beeffected by means of the relevant system.(iii) The Directors may in their absolute discretion and without assigning any reason thereforrefuse 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 takingplace on an open and proper basis.257

(iv) The Directors may also refuse to register the transfer of a certificated share unless theinstrument of transfer:(A) is lodged at the registered office or at another place appointed by the Directorsaccompanied by the certificate for the share to which it relates and such otherevidence as the Directors may reasonably require to show the right of the transferorto 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 sendthe transferee notice of the refusal within two months after the date on which theinstrument of transfer was lodged with the Company.(vi) No fee shall be charged for the registration of any instrument of transfer or otherdocument relating to or affecting the title to a share.(vii) The holder of the Special Voting Share may only transfer the Special Voting Share inaccordance 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 calledextraordinary general meetings.(ii) Except for the annual general meeting, the Directors shall convene and the Company shallhold general meetings as extraordinary general meetings in accordance with the Act. TheDirectors may call general meetings whenever they think fit. On the requisition ofmembers pursuant to the provisions of the Act, the Directors shall promptly convene anextraordinary general meeting.(iii) An annual general meeting and an extraordinary general meeting called for the passing ofa special resolution shall be called by at least 21 clear days’ written notice. All otherextraordinary general meetings shall be called by at least 14 days’ written notice. Subject tothe provisions of the Act, the provisions of the Articles and to any restrictions imposed onany shares, the notice shall be sent to all the members, to each of the directors and tothe auditors.(iv) The notice shall specify the time and place of the meeting and the general nature of thebusiness to be transacted at the meeting.(v) In the case of an annual general meeting, the notice shall specify the meeting as such. Inthe case of a meeting to pass a special resolution, the notice shall contain a statement tothat effect.(vi) The Company may specify in the notice a time, which may not be more than 48 hoursbefore the time fixed for the meeting, by which a person must be entered on the Companyregister 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 bedecided on a poll. Procedural resolutions shall be decided on a show of hands, unless apoll 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 onthe resolution;(C) a member or members present in person or by proxy and representing not less thanone-tenth of the total voting rights of all the members having the right to vote on theresolution;(D) a member or members present in person or by proxy and holding shares in theCompany conferring a right to vote at the meeting being shares on which anaggregate sum has been paid up equal to not less than one-tenth of the total sum paid258

up on all the shares conferring that right or, the member who is the holder of theSpecial 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 takenat a general meeting of the Company, and if required to do so the directors must appointan 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 speakat any general meeting and at any separate meeting of the holders of any class of shares inthe capital of the Company.(xi) The chairman may at any time, without the consent of the meeting, adjourn the meetingfor the purpose of declaring the results of a poll.(k) Voting rights(i) Ordinary SharesSubject to any special rights or restrictions as to voting attached to Ordinary Shares, on ashow of hands every member who is present in person or by proxy shall have one vote andon a poll every member who is present in person or by proxy shall have one vote for everyOrdinary Share of which he is the holder. On a poll, a person entitled to more than onevote need not use all his votes or cast all the votes he uses in the same way. A member mayappoint more than one proxy. No member shall be entitled to vote, unless the Directorsotherwise determine, at any general meeting unless all monies presently payable by him inrespect of shares in the Company have been paid. A shareholder which has been dulyserved 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 theinformation requested shall not be entitled to attend or vote personally or by proxy atshareholders’ meetings.(ii) Special Voting Share(A) The holders of Exchangeable Shares are entitled to Voting Rights and through theSpecial Voting Share held by the trustee of the Voting and Exchange Trust by theCompany, will have the right to receive notice of, speak and vote at general meetingsof the Company (on the basis of one vote for every Exchangeable Share) on the samebasis as if they had exchanged their Exchangeable Shares for Ordinary Shares, to becalculated in accordance with the Voting and Exchange Trust. In addition, where theCompany, inter alia, seeks to issue additional Ordinary Shares, is subject to atakeover offer, or reorganises its share capital, the Company will seek to put theholders of Exchangeable Shares in a similar position to the holders of OrdinaryShares.(B) The holder of the Special Voting Share may appoint more than one proxy to attendany general meeting in respect of all or a particular number of the votes attached tothe Special Voting Share, provided that: (i) each instrument appointing a proxy shallspecify the number of votes attached to the Special Voting Share for which therelevant person is appointed his proxy; (ii) each such person shall act as proxy for theholder of the Special Voting Share for the number of votes specified in the instrumentappointing the person as a proxy; (iii) the total number of such proxies shall notexceed the total number of votes the holder of the Special Voting Share would beentitled to exercise on a poll at such general meeting; and (iv) notwithstanding thenumber of proxies appointed by the holder of the Special Voting Share for anygeneral meeting, the holder of the Special Voting Share shall be deemed to constituteone member at such general meeting.259

(l)Directors(i) Appointment of DirectorsUnless otherwise determined by ordinary resolution, the number of Directors shall be notless than three nor more than twenty. Directors may be appointed by ordinary resolutionor by the Board and the Company may by ordinary resolution from time to time vary theminimum number and/or the maximum number of Directors.The Directors may appoint any one or more of their body to be executive Directors andconfer on them any powers exercisable by them as the Directors think fit.(ii) Age of DirectorsNo age limit shall apply to Directors.(iii) No Share QualificationA Director shall not be required to hold any shares in the capital of the Company by wayof qualification.(iv) Retirement of Directors by RotationExcept 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 ofthree, the number nearest to one third shall retire from office.(v) Remuneration of DirectorsThe emoluments of any Director holding executive office for his services as such shall bedetermined by the Board, and may be of any description. The ordinary remuneration ofthe 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 byordinary 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 andperforms services outside the scope of the ordinary duties of a Director, may be paid suchextra remuneration as the Board may determine. In addition to any remuneration to whichthe Directors are entitled under the Articles, they may be paid all reasonable expenses asthey may incur in attending and returning from meetings of the Directors or of anycommittee of the Directors or shareholders meetings or otherwise in connection with thebusiness of the Company.The Board may provide benefits, whether by the payment of gratuities or pensions or byother retirement, superannuation, death or disability benefits or otherwise, for any past orpresent Director, and for any member of his family or any person who is or was dependenton him.(vi) Directors LoansThe Company may make a loan to a director or give a guarantee or provide security inconnection with a loan made by any person to such director, provided that the transactionhas been approved by an ordinary resolution of the members. Approval for suchtransactions is not required provided the aggregate nominal value of the transaction doesnot exceed £10,000 (loans) or £15,000 (credit transactions), or in circumstances where theCompany has provided a director with funds of up to £50,000 to enable him to properlyperform his duties as an officer of the Company.(vii) Permitted interests of DirectorsSubject to the provisions of the Statutes, and provided that he has disclosed to the Boardthe nature and extent of any direct or indirect interest which conflicts or may conflict to amaterial 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 theCompany 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 corporatepromoted 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 officeof auditor) in conjunction with his office of director and may (and any firm of whichhe is a partner, employee or member may) act in a professional capacity for theCompany (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 benefitwhich he derives from any such office or employment or from any such transaction orarrangement or from any interest in any such body corporate and no such transactionor arrangement shall be liable to be avoided on the ground of any such interestor benefit.(viii) Restrictions on votingA Director shall not vote on any resolution of the Board concerning a matter in which hehas a direct or indirect interest which conflicts or may conflict to a material extent with theinterests of the Company but these prohibitions shall not apply to:(A) the giving of a guarantee, security or indemnity in respect of money lent orobligations incurred by him or any other person at the request of, or for the benefitof, the Company or any of its subsidiary undertakings;(B) the giving of a guarantee, security or indemnity in respect of a debt or obligation ofthe Company or any of its subsidiary undertakings for which the Director hasassumed 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 theCompany or any of its subsidiary undertakings for subscription or purchase, in whichoffer he is or may be entitled to participate as a holder of securities or in theunderwriting or sub-underwriting of which he is to participate;(D) a contract, arrangement, transaction or proposal concerning any other body corporatein which he or any person connected with him is interested, directly or indirectly, andwhether as an officer, shareholder, creditor or otherwise, if he and any personsconnected 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 anyother body corporate through which his interest is derived) or of the voting rightsavailable to members of the relevant body corporate (any such interest being deemedfor 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 subsidiaryundertakings which does not award him any privilege or benefit not generallyaccorded to the employees to whom the arrangement relates; and(F) a proposal concerning: (a) any insurance which the Company is empowered topurchase or maintain for, or for the benefit of, any Directors or for persons whoinclude Directors; or (b) indemnities in favour of the Directors; or (c) the funding ofexpenditure 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 suchexpenditure.(ix) Borrowing PowersThe Board may exercise all the powers of the Company to borrow money, to guarantee, toindemnify, to mortgage or charge its undertaking, property, assets (present and future)and uncalled capital, and to issue debentures and other securities whether outright or ascollateral security for any debt, liability or obligation of the Company or of any third party.(x) Indemnity of OfficersSubject to the provisions of the Act every Director shall be indemnified out of the assets ofthe 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 Sharesunless prior to such announcement or declaration the Company has received from thedirectors of HOC confirmation that HOC will announce or declare an equivalentdividend 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 theSpecial Voting Share.(C) Subject to the provisions of the Act, the Directors may pay fixed and interimdividends if and in so far as in the opinion of the Directors the profits of the Companyjustify such payments. If the Directors act in good faith, they shall not incur anyliability to the holders of any shares for any loss they may suffer by the lawfulpayment, on any other class of shares having rights ranking after or pari passu withthose shares, of any such fixed or interim dividend.(D) the Company may, upon the recommendation of the Directors, by ordinaryresolution, direct payment of a dividend in whole or in part in specie and the Directorsshall give effect to such resolution.(E) Except as otherwise provided by the rights attaching to any class of shares or theterms of issue thereof, all dividends shall be apportioned and paid pro rata accordingto the amounts paid on the shares during any period or portions of the period inrespect of which the dividend is paid.(F) No dividend or other monies payable in respect of a share shall bear interest againstthe Company.(G) The Directors may retain any dividend or monies payable in respect of a share onwhich the Company has a lien, and may apply the same in or towards satisfaction ofthe 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 ofshares on or in respect of such shares all sums of money (if any) presently payable bythe 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 suchdividend was declared or became due for payment shall be forfeited and revert tothe Company.(J) The Directors may, if authorised by an ordinary resolution of the Company, offer anyholder of shares the right to elect to receive shares by way of scrip dividend insteadof cash.(xii) Winding-UpExcept as provided by the rights and restrictions attached to any class of shares, theholders of Ordinary Shares will be entitled to participate in any surplus assets in a windingup in proportion to their shareholdings. The Company may, with the sanction of a specialresolution and any other sanction required by the Act, divide among the members in speciethe whole or any part of the assets of the Company and may, for that purpose, value anyassets and determine how the division shall be carried out as between the members ordifferent classes of members.The holder of the Special Voting Share shall be entitled, subject to the payment to theholders of all other classes of shares, of the amount paid up or credited as paid up orotherwise payable on such share, to repayment of the amount paid upon the SpecialVoting Share but shall have no further right to participate in the assets of the Company.(m) Disclosure of Beneficial InterestsAlthough the Act does not contain equivalent provisions to section 793 of the New CompaniesAct, the Articles provide broadly equivalent provisions and provide that if at any time anymember, or any other person (as appropriate) has been served with a notice from the company262

and is in default for a period of 14 days supplying to the Company the information therebyrequired, 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 towhom any of such shares are transferred (other than pursuant to an approved transfer) beentitled to vote either personally or by proxy at a shareholders’ meeting or to exercise anyother 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 suchmember direct that where the default shares represent 0.25 per cent. or more of the issuedshares of the class in question, the direction notice may additionally direct that in respectof the default shares:(I) no payment shall be made by way of dividend and no share shall be allotted in lieu ofpayment of a dividend; and(II) subject to the Regulations in the case of shares in uncertificated form, no transfer ofany default share shall be registered unless:1. the transfer is an approved transfer; or2. the member is not himself in default as regards supplying the informationrequired and the transfer is of part only of the member’s holding and whenpresented for registration, is accompanied by a certificate from the member in aform satisfactory to the Board to the effect that after due and careful enquiry themember is satisfied that none of the shares the subject of the transfer is adefault share.Any direction notice shall cease to have effect in relation to any shares transferred by suchmember in accordance with the provisions described in section 6.2 (k)(xiii)(B)(II) above.(n) AccountsAlthough the Act does not contain equivalent provisions of the New Companies Act on a rangeof matters, the Articles provide broadly equivalent provisions in relation to the publication ofaccounts, 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 theNew 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 theArticles, and are made available as soon as reasonably practicable on a website and remainso available until the annual accounts and reports for the Company’s next financial yearare made so available; and(iii) the Company complies with Chapters 7 to 9 (inclusive) (Publication of Accounts andReport, Public Companies: Laying of Accounts and Reports before General Meeting, andQuoted Companies: Members’ Approval of Directors’ Remuneration Report) of Part 15of the New Companies Act mutatis mutandis as if it were a company subject tosuch statute.(o) Communications to all beneficial holders of SharesAlthough the Act does not contain equivalent provisions of the New Companies Act on a rangeof matters, the Articles provide broadly equivalent provisions in relation to communications tobeneficial holders of shares, namely that a member who holds shares on behalf of anotherperson may nominate that person to enjoy information rights (being the right to receive a copyof 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 hasbeen supplied and the Company has been notified)). Failure to give effect to the rightsconferred by the nomination does not affect the validity of anything done by or on behalf ofthe Company.263

6.3 Terms and Conditions of Exchangeable SharesThe Articles of HOC have been adopted and include the following terms and conditions of theExchangeable Shares.(a) Ranking of Exchangeable SharesThe Exchangeable Shares shall be entitled to a preference over the HOC Shares and any othershares ranking junior to the Exchangeable Shares with respect to the payment of dividends andthe 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 itsshareholders for the purpose of winding up its affairs.(b) DividendsA holder of an Exchangeable Share shall be entitled to receive and the HOC Board ofDirectors 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 foreach Exchangeable Share, at the election of HOC in United States currency or theCanadian Dollar Equivalent thereof on the HOC Dividend Declaration Date, in eachcase, 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 OrdinaryShares in such number of Exchangeable Shares for each Exchangeable Share as is equal tothe 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 orOrdinary Shares, in such type and amount of property for each Exchangeable Share as isthe same as or economically equivalent to (to be determined by the HOC Board ofDirectors as contemplated by this Part X, section 6.3(b)) the type and amount of propertydeclared as a dividend on each Ordinary Share.Such dividends shall be paid out of money, assets or property of HOC properly applicable tothe payment of dividends, or out of authorized but unissued shares of HOC, as applicable. Theholders of Exchangeable Shares shall not be entitled to any dividends other than or in excess ofthe 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 respectof any cash dividends contemplated by this Part X, section 6.3(b) and the sending of such acheque to each holder of an Exchangeable Share shall satisfy the cash dividend representedthereby unless the cheque is not paid on presentation. Certificates registered in the name ofthe holder of Exchangeable Shares shall be issued or transferred in respect of any stockdividends contemplated by this Part X, section 6.3(b) and the sending of such a certificate toeach 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 thisPart X, section 6.3(b) shall be issued, distributed or transferred by HOC in such manner as itshall determine and the issuance, distribution or transfer thereof by HOC to each holder of anExchangeable 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 processagainst HOC any dividend that is represented by a cheque that has not been duly presented toHOC’s bankers for payment or that otherwise remains unclaimed for a period of six years fromthe date on which such dividend was payable.The record date for the determination of the holders of Exchangeable Shares entitled toreceive payment of, and the payment date for, any dividend declared on the ExchangeableShares under this Part X, section 6.3(b) shall be the same dates as the record date and paymentdate, 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 thisPart X, section 6.3(b) the dividends are not paid in full on all of the Exchangeable Shares thenoutstanding, any such dividends that remain unpaid shall be paid, subject to applicable law, ona subsequent date or dates determined by the HOC Board of Directors on which HOC shall264

(c)have sufficient moneys, assets or property properly applicable to the payment ofsuch dividends.The HOC Board of Directors shall determine, in good faith and in its sole discretion, economicequivalence for the purposes of this Part X, section 6.3(b), and each such determination shallbe 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 ofDirectors 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 thenumber of such shares issued as a result of such stock dividend in proportion to thenumber of Ordinary Shares previously outstanding;(ii) in the case of the issuance or distribution of any rights, options or warrants to subscribe foror purchase Ordinary Shares (or securities exchangeable for or convertible into or carryingrights to acquire Ordinary Shares), the relationship between the Canadian DollarEquivalent of the exercise price of each such right or option and the Current Market Priceof an Ordinary Share;(iii) in the case of the issuance or distribution of any other form of property (including withoutlimitation any shares or securities of the Company of any class other than OrdinaryShares, any rights, options or warrants other than those referred to above, any evidencesof indebtedness of the Company or any assets of the Company), the relationship betweenthe fair market value (as determined by the HOC Board of Directors in the manner abovecontemplated) of such property to be issued or distributed with respect to eachoutstanding 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 OrdinaryShares into a greater number of Ordinary Shares or the reduction, combination,consolidation or change of the then outstanding Ordinary Shares into a lesser number ofOrdinary Shares or any amalgamation, merger, reorganisation or other transactionaffecting Ordinary Shares, the effect thereof upon the then outstanding OrdinaryShares; and(v) in all such cases, the general taxation consequences of the relevant event to holders ofExchangeable Shares to the extent that such consequences may differ from the taxationconsequences to holders of Ordinary Shares as a result of differences between taxationlaws of Canada and Jersey (except for any differing consequences arising as a result ofdiffering marginal taxation rates and without regard to the individual circumstances ofholders of Exchangeable Shares).Certain RestrictionsSo long as any of the Exchangeable Shares are outstanding (other than Exchangeable Sharesheld by the Company and its Affiliates), HOC shall not at any time without, but may at anytime 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 theExchangeable Shares, other than stock dividends payable in HOC Common Shares or anysuch 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 Sharesor any other shares ranking junior to the Exchangeable Shares;(iii) redeem or purchase any other shares of HOC ranking equally with the ExchangeableShares 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, orsuperior to, the Exchangeable Shares other than by way of stock dividends to the holdersof 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 ifall dividends on the outstanding Exchangeable Shares corresponding to dividends declared and265

paid to date on the Ordinary Shares shall have been declared and paid on the ExchangeableShares.(d) Distribution on LiquidationIn the event of the liquidation, dissolution or winding-up of HOC or any other distribution ofthe assets of HOC among its shareholders for the purpose of winding up its affairs, a holder ofExchangeable Shares shall be entitled, subject to applicable law and to the exercise by CallCoof the Liquidation Call Right, to receive from the assets of HOC in respect of eachExchangeable 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 assetsof HOC among the holders of the HOC Common Shares or any other shares ranking junior tothe Exchangeable Shares, an amount per share equal to the Current Market Price of anOrdinary Share on the last Business Day prior to the HOC Liquidation Date, which shall besatisfied in full by HOC causing to be delivered to such holder one Ordinary Share, togetherwith all declared and unpaid dividends on each such Exchangeable Share held by such holderon any dividend record date which occurred prior to the HOC Liquidation Date (the ‘‘HOCLiquidation Amount’’).On or promptly after the HOC Liquidation Date, and subject to the exercise by CallCo of theLiquidation Call Right, HOC shall cause to be delivered to the holders of the ExchangeableShares the HOC Liquidation Amount for each such Exchangeable Share upon surrender of theExchangeable Shares, together with such other documents and instruments as may be requiredto effect a transfer of Exchangeable Shares under the ABCA and the constating documents ofHOC and such additional documents and instruments as the Transfer Agent may reasonablyrequire, at the registered office of HOC or at any office of the Transfer Agent as may bespecified by HOC by notice to the holders of the Exchangeable Shares. Payment of the totalHOC 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 registerof HOC for the Exchangeable Shares, or by holding for pick-up on the instructions of theholder at the registered office of HOC or at any office of the Transfer Agent as may bespecified by HOC by notice to the holders of Exchangeable Shares, on behalf of HOCcertificates representing Ordinary Shares (which shares shall be duly issued as fully paidand shall be free and clear of any lien, claim or encumbrances) and a cheque of HOCpayable at par at any branch of the bankers of HOC in respect of the declared and unpaiddividends on the Exchangeable Shares of such holder (in each case less any amountswithheld 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 fullypaid and shall be free and clear of any lien, claim or encumbrances) to CREST accountson behalf of each holder and by delivery to each holder a cheque of HOC payable at par atany branch of the bankers of HOC in respect of the declared and unpaid dividends on theExchangeable Shares of such holder (in each case less any amounts withheld on account oftax required to be deducted and withheld therefrom).On and after the Heritage Liquidation Date, the holders of the Exchangeable Shares shallcease to be holders of such Exchangeable Shares and shall not be entitled to exercise any of therights of holders in respect thereof, other than the right to receive their proportionate part ofthe total Heritage Liquidation Amount, unless payment of the total Heritage LiquidationAmount for such Exchangeable Shares shall not be made upon surrender of the ExchangeableShares in accordance with the foregoing provisions, in which case the rights of the holders shallremain unaffected until the total Heritage Liquidation Amount has been paid in the mannerhereinbefore provided. HOC shall have the right at any time after the Heritage LiquidationDate to deposit or cause to be deposited certificates representing the Ordinary Shares issuablein respect of, and an amount representing declared and unpaid dividends on, the ExchangeableShares represented by certificates or beneficial interests that have not, at the HOC LiquidationDate, been surrendered by the holders thereof, in a custodial account with any chartered bankor trust company in Canada. Upon such deposit being made, the rights of the holders ofExchangeable Shares after such deposit shall be limited to receiving their proportionate part ofthe total HOC Liquidation Amount (in each case less any amounts withheld on account of taxrequired to be deducted and withheld therefrom) for such Exchangeable Shares so deposited,266

(e)against surrender of the Exchangeable Shares held by them, in accordance with the foregoingprovisions. Upon such payment or deposit of the total HOC Liquidation Amount and subjectto the relevant entries being made in the register of members of the Company, the holders ofthe Exchangeable Shares shall thereafter be considered and deemed for all purposes to beholders 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 HOCLiquidation Amount per Exchangeable Share pursuant to Part X, section 6.3(d) of these shareprovisions, such holders shall not be entitled to share in any further distribution of the assetsof HOC.Retraction of Exchangeable Shares by holderA holder of Exchangeable Shares shall be entitled at any time, subject to the exercise by CallCoof the CallCo Redemption Call Right and otherwise upon compliance with the provisions ofthis Part X, section 6.3(e), to require HOC to redeem any or all of the Exchangeable Sharesregistered in the name of such holder for an amount per share equal to the Current MarketPrice 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 tosuch holder one Ordinary Share for each Exchangeable Share presented and surrendered bythe holder, together with, on the payment date therefor, the full amount of all declared andunpaid dividends on any such Exchangeable Share (the ‘‘Dividend Amount’’) held by suchholder 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 atthe registered office of HOC or at any office of the Transfer Agent as may be specified by HOCby notice to the holders of Exchangeable Shares the certificate or certificates representing theExchangeable Shares which the holder desires to have HOC redeem, together with such otherdocuments and instruments as may be required to effect a transfer of Exchangeable Sharesunder the ABCA and the constating documents of HOC and such additional documents andinstruments as the Transfer Agent may reasonably require, and together with a duly executedstatement (the ‘‘Retraction Request’’):(i) specifying that the holder desires to have all or any number specified therein of theExchangeable Shares represented by such certificate or certificates (the ‘‘RetractedShares’’) redeemed by HOC;(ii) stating the Business Day on which the holder desires to have HOC redeem the RetractedShares (the ‘‘Retraction Date’’), provided that the Retraction Date shall be not less than15 Business Days nor more than 20 Business Days after the date on which the RetractionRequest is received by HOC and further provided that, in the event that no such BusinessDay is specified by the holder in the Retraction Request, the Retraction Date shall bedeemed to be the 20 th Business Day after the date on which the Retraction Request isreceived by HOC; and(iii) acknowledging the overriding right (the ‘‘CallCo Redemption Call Right’’) of CallCo topurchase all but not less than all the Retracted Shares directly from the holder and thatthe Retraction Request shall be deemed to be a revocable offer by the holder to sell theRetracted Shares to CallCo in accordance with the CallCo Redemption Call Right on theterms 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 theOrdinary Shares (an ‘‘Offer’’), HOC will use its commercially reasonable efforts, expeditiouslyand in good faith, to put in place procedures or cause the Transfer Agent to put in placeprocedures to ensure that, if holders of Exchangeable Shares are required to retract suchExchangeable Shares to participate in the Offer, that any such retraction shall be conditionalupon and shall only be effective if the Ordinary Shares tendered or deposited under such Offerare taken up, and (ii) notwithstanding any other provision of these Exchangeable Shareprovisions, holders of Exchangeable Shares who are Persons in the United States or are aU.S. Person may not exercise the Retraction Right.Subject to the exercise by CallCo of the CallCo Redemption Call Right, upon receipt by HOCor the Transfer Agent in the manner as specified herein, of a certificate or certificates267

epresenting the Retracted Shares, together with a Retraction Request, and provided that theRetraction 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 theRetraction Date and shall deliver or cause to be delivered to such holder certificatesrepresenting 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 ofthe bankers of HOC in respect of any dividends on the Retracted Shares for which the recorddate 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 andwithheld therefrom). If only a part of the Exchangeable Shares represented by any certificateare redeemed (or purchased by CallCo pursuant to the CallCo Redemption Call Right), a newcertificate for the balance of such Exchangeable Shares shall be issued to the holder at theexpense of HOC.Upon receipt by HOC of a Retraction Request, HOC shall immediately notify CallCo thereofand shall provide CallCo with a copy of the Retraction Request. In order to exercise the CallCoRedemption Call Right, CallCo must notify HOC of its determination to do so (the ‘‘CallCoCall Notice’’) within five Business Days of notification to CallCo by HOC of the receipt by HOCof the Retraction Request. If CallCo does not so notify HOC within such five Business Dayperiod, HOC will notify the holder as soon as possible thereafter that CallCo will not exercisethe CallCo Redemption Call Right. If CallCo delivers the CallCo Call Notice within such fiveBusiness Day period, and provided that the Retraction Request is not revoked by the holder inthe manner specified in this Part X, section 6.3(e), the Retraction Request shall thereupon beconsidered only to be an offer by the holder to sell the Retracted Shares to CallCo inaccordance with the CallCo Redemption Call Right. In such event, HOC shall not redeem theRetracted Shares and CallCo shall purchase from such holder and such holder shall sell toCallCo on the Retraction Date the Retracted Shares for a purchase price per share equal tothe Retraction Price per share (the ‘‘Purchase Price’’). To the extent that CallCo pays theDividend Amount in respect of the Retracted Shares, HOC shall no longer be obligated to payany declared and unpaid dividends on such Retracted Shares. Provided that CallCo hascomplied with this Part X, section 6.3(e), the closing of the purchase and sale of the RetractedShares pursuant to the CallCo Redemption Call Right shall be deemed to have occurred as atthe close of business on the Retraction Date and, for greater certainty, no redemption by HOCof such Retracted Shares shall take place on the Retraction Date. In the event that CallCo doesnot deliver a CallCo Call Notice within such five Business Day period, and provided that theRetraction 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 themanner otherwise contemplated in this Part X, section 6.3(e). Notwithstanding any otherprovision of these Exchangeable Share provisions, the Exchangeable Shares that are thesubject of a Retraction Request may not be purchased by CallCo if such Exchangeable Sharesare 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 ofthe holder recorded in the securities register of HOC for the Exchangeable Shares or atthe address specified in the holder’s Retraction Request or by holding for pick-up by theholder at the registered office of HOC or at any office of the Transfer Agent as may bespecified by HOC by notice to the holders of Exchangeable Shares, certificatesrepresenting the Ordinary Shares (which shares shall be duly issued as fully paid and shallbe free and clear of any lien, claim or encumbrance) registered in the name of the holderor in such other name as the holder may request, and, if applicable and on or before thepayment date therefor, a cheque payable at par at any branch of the bankers of HOC orCallCo, as applicable, representing the aggregate Dividend Amount in payment of thetotal Retraction Price or the total Purchase Price, as the case may be, in each case, less anyamounts withheld on account of tax required to be deducted and withheld therefrom, andsuch delivery of such certificates and cheques on behalf of HOC or by CallCo, as the casemay be, or by the Transfer Agent shall be deemed to be payment of and shall satisfy anddischarge all liability for the total Retraction Price or total Purchase Price, as the case may268

e, to the extent that the same is represented by such share certificates and cheques (plusany 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, claimor 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 securitiesregister of HOC for the Exchangeable Shares or at the address specified in the holder’sRetraction Request or by holding for pick-up by the holder at the registered office ofHOC or at any office of the Transfer Agent as may be specified by HOC by notice to theholders of Exchangeable Shares, a cheque payable at par at any branch of the bankers ofHOC or CallCo, as applicable, representing the aggregate Dividend Amount in paymentof 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 withheldtherefrom, 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 shallsatisfy and discharge all liability for the total Retraction Price or total Purchase Price, asthe case may be, to the extent that the same is represented by such CREST account creditsand cheques (plus any tax deducted and withheld therefrom and remitted to the propertax authority).On and after the close of business on the Retraction Date, the holder of the Retracted Sharesshall cease to be a holder of such Retracted Shares and shall not be entitled to exercise any ofthe rights of a holder in respect thereof, other than the right to receive his proportionate partof the total Retraction Price or total Purchase Price, as the case may be, unless upon surrenderof the Retracted Shares in accordance with the foregoing provisions payment of the totalRetraction Price or the total Purchase Price, as the case may be, shall not be made as providedin this Part X, section 6.3(e), in which case the rights of such holder shall remain unaffecteduntil the total Retraction Price or the total Purchase Price, as the case may be, has been paid inthe 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 Priceor the total Purchase Price, as the case may be, has been made in accordance with theforegoing provisions and subject to the relevant entries being made in the register of membersof the Company, the holder of the Retracted Shares so redeemed by HOC or purchased byCallCo shall thereafter be considered and deemed for all purposes to be a holder of theOrdinary Shares delivered to it.Notwithstanding any other provision of this Article 6, HOC shall not be obligated to redeemRetracted Shares specified by a holder in a Retraction Request to the extent that suchredemption of Retracted Shares would be contrary to solvency requirements or otherprovisions of applicable law. If HOC believes that on any Retraction Date it would not bepermitted by any of such provisions to redeem the Retracted Shares tendered for redemptionon such date, and provided that CallCo shall not have exercised the CallCo Redemption CallRight with respect to the Retracted Shares, HOC shall only be obligated to redeem RetractedShares specified by a holder in a Retraction Request to the extent of the maximum numberthat may be so redeemed (rounded down to a whole number of shares) as would not becontrary to such provisions and shall notify the holder at least two Business Days prior to theRetraction Date as to the number of Retracted Shares which will not be redeemed by HOC. Inany case in which the redemption by HOC of Retracted Shares would be contrary to solvencyrequirements or other provisions of applicable law, HOC shall redeem Retracted Shares inaccordance with this Part X, section 6.3(e) on a pro rata basis and shall either issue to eachholder of Retracted Shares a new certificate, at the expense of HOC, or deposit, electronicallyor otherwise, with the applicable nominee, Exchangeable Shares, representing the RetractedShares not redeemed by HOC pursuant to this Part X, section 6.3(e). Provided that theRetraction 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 thisPart X, section 6.3(e) of these share provisions as a result of solvency requirements or otherprovisions of applicable law shall be deemed by giving the Retraction Request, subject to theimmediately following sentence, to require the Company to purchase such Retracted Sharesfrom such holder on the Retraction Date or as soon as practicable thereafter on payment by269

(f)the Company to such holder of the Purchase Price for each such Retracted Share, all as morespecifically provided in the Voting and Exchange Trust Agreement. Notwithstanding theimmediately preceding sentence, the Company will not be required to purchase any RetractedShares form holders thereof pursuant to this Part X, section 6.3(e) or the Voting and ExchangeTrust 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 inaccordance with Part X, section 6.3(m) before the close of business on the Business Dayimmediately preceding the Retraction Date, withdraw its Retraction Request, in which eventsuch Retraction Request shall be null and void and, for greater certainty, the revocable offerconstituted by the Retraction Request to sell the Retracted Shares to CallCo shall be deemedto have been revoked.Redemption of Exchangeable Shares by HOCSubject to applicable law, and provided CallCo has not exercised the CallCo Redemption CallRight, HOC shall on the Redemption Date redeem all but not less than all of the outstandingExchangeable Shares for an amount per share equal to the Current Market Price of anOrdinary Share on the last Business Day prior to the Redemption Date (the ‘‘HeritageRedemption Right’’), which shall be satisfied in full by HOC causing to be delivered to eachholder of Exchangeable Shares one Ordinary Share for each Exchangeable Share held by suchholder, together with the full amount of all declared and unpaid dividends on each suchExchangeable Share held by such holder on any dividend record date which occurred prior tothe Redemption Date (the ‘‘Redemption Price’’).In any case of a redemption of Exchangeable Shares under this Part X, section 6.3(f), HOCshall, at least sixty (60) days before the Redemption Date (other than a Redemption Dateestablished in connection with a Company Control Transaction, an Exchangeable Share VotingEvent or an Exempt Exchangeable Share Voting Event), send or cause to be sent to eachholder of Exchangeable Shares a notice in writing of the redemption by HOC or the purchaseby CallCo under the CallCo Redemption Call Right, as the case may be, of the ExchangeableShares held by such holder. In the case of a Redemption Date established in connection with aCompany Control Transaction, an Exchangeable Share Voting Event and an ExemptExchangeable Share Voting Event, the written notice of redemption by HOC or the purchaseby CallCo under the CallCo Redemption Call Right will be sent on or before the RedemptionDate, on as many days prior written notice as may be determined by the HOC Board ofDirectors to be reasonably practicable in the circumstances. In any such case, such notice shallset out the formula for determining the Redemption Price or the Redemption Call PurchasePrice, as the case may be, the Redemption Date and, if applicable, particulars of the HOCRedemption Call Right.On or after the Redemption Date and subject to the exercise by CallCo of the CallCoRedemption Call Right, HOC shall cause to be delivered to the holders of the ExchangeableShares to be redeemed the Redemption Price for each such Exchangeable Share, uponsurrender at the registered office of HOC or at any office of the Transfer Agent as may bespecified by HOC in such notice of the Exchangeable Shares, together with such otherdocuments and instruments as may be required to effect a transfer of Exchangeable Sharesunder the ABCA and the constating documents of HOC and such additional documents andinstruments as the Transfer Agent may reasonably require. Payment of the total RedemptionPrice for such Exchangeable Shares, together with payment of such dividends, shall bemade either(i) by delivery to each holder, at the address of the holder recorded in the securities registerof HOC or by holding for pick-up by the holder at the registered office of HOC or at anyoffice of the Transfer Agent as may be specified by HOC in such notice, certificatesrepresenting Ordinary Shares (which shares shall be duly issued as fully paid and shall befree and clear of any lien, claim or encumbrance) and, if applicable, a cheque of HOCpayable at par at any branch of the bankers of HOC in payment of any such dividends, ineach case, less any amounts withheld on account of tax required to be deducted andwithheld therefrom; or270

(g)(ii) by arranging for the credit of Ordinary Shares (which shares shall be duly issued as fullypaid and shall be free and clear of any lien, claim or encumbrances) to CREST accountson behalf of each holder and, if applicable, delivery to each holder, at the address of theholder recorded in the securities register of HOC or by holding for pick-up by the holderat the registered office of HOC or at any office of the Transfer Agent as may be specifiedby HOC in such notice, a cheque of HOC payable at par at any branch of the bankers ofHOC in payment of any such dividends, in each case, less any amounts withheld onaccount of tax required to be deducted and withheld therefrom).On and after the Redemption Date, the holders of the Exchangeable Shares called forredemption shall cease to be holders of such Exchangeable Shares and shall not be entitled toexercise any of the rights of holders in respect thereof, other than the right to receive theirproportionate part of the total Redemption Price and any such dividends, unless payment ofthe total Redemption Price and any such dividends for such Exchangeable Shares shall not bemade upon surrender of Exchangeable Shares in accordance with the foregoing provisions, inwhich case the rights of the holders shall remain unaffected until the total Redemption Priceand any such dividends have been paid in the manner hereinbefore provided. HOC shall havethe right at any time after the sending of notice of its intention to redeem the ExchangeableShares as aforesaid to deposit or cause to be deposited the total Redemption Price for, and thefull amount of such dividends on (except as provided in this Part X, section 6.3(f)), theExchangeable Shares so called for redemption, or such of the said Exchangeable Sharesrepresented by certificates that have not at the date of such deposit been surrendered by theholders thereof in connection with such redemption, in a custodial account with any charteredbank or trust company in Canada named in such notice, less any amounts withheld on accountof tax required to be deducted and withheld therefrom. Upon the later of such deposit beingmade and the Redemption Date, the Exchangeable Shares in respect whereof such depositshall have been made shall be redeemed and the rights of the holders thereof after such depositor Redemption Date, as the case may be, shall be limited to receiving their proportionate partof 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 foregoingprovisions. Upon such payment or deposit of the total Redemption Price and the full amountof such dividends and subject to the relevant entries being made in the register of members ofthe Company, the holders of the Exchangeable Shares shall thereafter be considered anddeemed for all purposes to be holders of the Ordinary Shares delivered to them or thecustodian on their behalf.Purchase for cancellation(i) Subject to applicable law and notwithstanding anything in this Part X, section 6.3(g), HOCmay, at any time and from time to time purchase for cancellation all or any part of theExchangeable Shares by private agreement with any holder of Exchangeable Shares forconsideration consisting of Ordinary Shares.(ii) Subject to applicable law and the articles of HOC, HOC may at any time and from time totime purchase for cancellation all or any part of the outstanding Exchangeable Shares atany price by tender to all the holders of record of Exchangeable Shares then outstandingor through the facilities of any stock exchange on which the Exchangeable Shares arelisted or quoted at any price per share. If in response to an invitation for tenders under theprovisions of this Part X, section 6.3(g), more Exchangeable Shares are tendered at a priceor prices acceptable to HOC than HOC is prepared to purchase, the Exchangeable Sharesto be purchased by HOC shall be purchased as nearly as may be pro rata according to thenumber of shares tendered by each holder who submits a tender to HOC, provided thatwhen shares are tendered at different prices, the pro rating shall be effected (disregardingfractions) only with respect to the shares tendered at the price at which more shares weretendered than HOC is prepared to purchase after HOC has purchased all the sharestendered at lower prices. If part only of the Exchangeable Shares represented by anycertificate shall be purchased a new certificate for the balance of such shares shall beissued at the expense of HOC.271

(h) Voting rightsExcept as required by applicable law and by Part X, section 6.3(i) below, the holders of theExchangeable Shares shall not be entitled as such to receive notice of or to attend any meetingof the shareholders of HOC or to vote at any such meeting. The holders of the ExchangeableShares shall, however, be entitled to notice of meetings of the shareholders called for thepurpose of authorizing the dissolution of HOC or the sale, lease or exchange or all orsubstantially 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 Sharesmay be added to, changed or removed but only with the approval of the holders of theHOC Common Shares given in accordance with the ABCA and the approval of theholders of the Exchangeable Shares given as hereinafter specified.(ii) Any approval given by the holders of the Exchangeable Shares to add to, change orremove any right, privilege, restriction or condition attaching to the Exchangeable Sharesor any other matter requiring the approval or consent of the holders of the ExchangeableShares shall be deemed to have been sufficiently given if it shall have been given inaccordance with applicable law subject to a minimum requirement that such approval beevidenced by resolution passed by not less than two-thirds of the votes cast on suchresolution at a meeting of holders of Exchangeable Shares duly called and held at whichthe holders of at least 25 per cent. of the outstanding Exchangeable Shares at that time arepresent or represented by proxy; provided that if at any such meeting the holders of atleast 25 per cent. of the outstanding Exchangeable Shares at that time are not present orrepresented by proxy within one-half hour after the time appointed for such meeting, thenthe meeting shall be adjourned to such date not less than five days thereafter and to suchtime and place as may be designated by the Chairman of such meeting. At such adjournedmeeting the holders of Exchangeable Shares present or represented by proxy thereat maytransact the business for which the meeting was originally called and a resolution passedthereat by the affirmative vote of not less than two-thirds of the votes cast on suchresolution at such meeting shall constitute the approval or consent of the holders of theExchangeable Shares.(j) Reciprocal changes, etc. in respect of Ordinary SharesEach holder of an Exchangeable Share acknowledges that the Support Agreement provides, inpart, that so long as Exchangeable Shares not owned by the Company or its Affiliates areoutstanding, the Company will not without the prior approval of HOC and CallCo and theprior 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 orcarrying rights to acquire Ordinary Shares) to the holders of all or substantially all of thethen outstanding Ordinary Shares by way of stock dividend or other distribution, otherthan an issue of Ordinary Shares (or securities exchangeable for or convertible into orcarrying rights to acquire Ordinary Shares) to holders of Ordinary Shares who exercise anoption to receive dividends in Ordinary Shares (or securities exchangeable for orconvertible into or carrying rights to acquire Ordinary Shares) in lieu of receivingcash dividends;(ii) issue or distribute rights, options or warrants to the holders of all or substantially all of thethen outstanding Ordinary Shares entitling them to subscribe for or to purchase OrdinaryShares (or securities exchangeable for or convertible into or carrying rights to acquireOrdinary Shares); or(iii) issue or distribute to the holders of all or substantially all of the then outstanding OrdinaryShares:(a) shares or securities of the Company of any class other than Ordinary Shares (otherthan shares convertible into or exchangeable for or carrying rights to acquireOrdinary 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 ofthe Exchangeable Shares.Each holder of an Exchangeable Share acknowledges that the Support Agreement furtherprovides, in part, that so long as Exchangeable Shares not owned by the Company or itsAffiliates are outstanding, the Company will not without the prior approval of HOC andCallCo and the prior approval of the holders of the Exchangeable Shares given in accordancewith Part X, section 6.3(i) of these share provisions:(i) subdivide, redivide or change the then outstanding Ordinary Shares into a greater numberof Ordinary Shares;(ii) reduce, combine, consolidate or change the then outstanding Ordinary Shares into a lessernumber 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 inthe rights of the holders of, the Exchangeable Shares. The Support Agreement furtherprovides, in part, that the aforesaid provisions of the Support Agreement shall not be changedwithout the approval of the holders of the Exchangeable Shares given in accordance withPart X, section 6.3(i) of these share provisions (other than certain amendments which are notprejudicial to the rights or interests of the holders of Exchangeable Shares).Each holder of an Exchangeable Share acknowledges that the Support Agreement furtherprovides, in part, that the Company will not, without the prior approval of HOC and the priorapproval 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 orentity other than the Company or any of its Affiliates, cease to remain the direct or indirectbeneficial 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 inaccordance with Part X, section 6.3(i) issue any shares of its capital stock in the same class asthe Special Voting Share and will not amend or modify the Voting and Exchange TrustAgreement 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 shareprovisions.If the Company at any time after the date hereof, consummates any transaction (whether byway of reconstruction, arrangement, reorganisation, consolidation, merger, transfer, sale, leaseor otherwise) whereby all or substantially all of its undertaking, property and assets wouldbecome the property of any other Person or, in the case of a merger, of the continuingcorporation 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 ofshares in the capital of the Company are entitled to receive shares or other ownership interestin the capital of any corporation or other legal entity other than such other Person orcontinuing corporation, then such corporation or other legal entity in which holders of sharesin the capital of the Company are entitled to receive an interest) is herein called the ‘‘CompanySuccessor’’) then, provided that the Company Successor is bound, or has agreed to be boundby the provisions of the Voting and Exchange Trust Agreement and Support Agreement and toassume the obligations of the Company thereunder to the satisfaction of the HOC Board ofDirectors, all references in these share provisions to Ordinary Shares shall be deemed to bereferences to the shares of the Company Successor, without amendment to these shareprovisions or any further action whatsoever. For greater certainty, if a transaction described in273

this Part X, section 6.3(j) results in holders of Exchangeable Shares being entitled to exchangetheir Exchangeable Shares for shares of a Company Successor in a different ratio then that setout in these share provisions, then these share provisions shall be deemed to be amended torefer to such different ratio(s).(k) Actions by HOC under Support AgreementHOC will take all such actions and do all such things as shall be necessary or advisable toperform 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 theCompany, DutchCo, CallCo and HOC, respectively, in accordance with the terms thereofincluding, without limitation, taking all such actions and doing all such things as shall benecessary or advisable to enforce to the fullest extent possible for the direct benefit of HOC allrights 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 orforgiveness of its rights or obligations under the Support Agreement without the approval ofthe holders of the Exchangeable Shares given in accordance with Part X, section 6.3(i) of theseshare provisions other than such amendments, waivers and/or forgiveness as may be necessaryor advisable for the purposes of(i) adding to the covenants of any or all parties to such agreement for the protection of theCompany or the holders of the Exchangeable Shares thereunder provided that the boardof directors of each of HOC, CallCo, DutchCo and the Company shall be of the good faithopinion that such additions will not be prejudicial to the rights or interests of the holdersof Exchangeable Shares;(ii) making such provisions or modifications not inconsistent with such agreement as may benecessary or desirable with respect to matters or questions arising thereunder which, in thegood faith opinion of the board of directors of each of HOC, CallCo, DutchCo and theCompany, it may be expedient to make, provided that each such board of directors shallbe of the good faith opinion, after consultation with legal counsel, that such provisions andmodifications will not be prejudicial to the interests of the holders of the ExchangeableShares; or(iii) making such changes in or corrections to such agreement which, on the advice of counselto HOC, CallCo, DutchCo and the Company, are required for the purpose of curing orcorrecting any ambiguity or defect or inconsistent provision or clerical omission or mistakeor 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 consultationwith counsel, that such changes or corrections will not be prejudicial to the interests of theholders of the Exchangeable Shares.(l) Legend; Call RightsThe certificates evidencing the Exchangeable Shares shall contain or have affixed thereto alegend in form and on terms approved by the HOC Board of Directors, with respect to theSupport Agreement, the provisions of the Plan of Arrangement relating to the Liquidation CallRight, the Retraction Right and the CallCo Redemption Call Right, and the Voting andExchange Trust Agreement (including the provisions with respect to the voting rights, exchangerights and automatic exchange thereunder).Each holder of an Exchangeable Share, whether of record or beneficial, by virtue of becomingand being such a holder shall be deemed to acknowledge each of the Liquidation Call Rightand the CallCo Redemption Call Right, in each case, in favour of CallCo, and the overridingnature thereof in connection with the liquidation, dissolution or winding-up of HOC or theredemption of Exchangeable Shares, as the case may be, and to be bound thereby in favour ofCallCo as therein provided.HOC, CallCo, DutchCo, the Company and the Transfer Agent shall be entitled to deduct andwithhold from any dividend or consideration otherwise payable to any holder of ExchangeableShares such amounts as HOC, CallCo, DutchCo, the Company or the Transfer Agent isrequired 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 or274

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 allpurposes hereof as having been paid to the holder of such Exchangeable Shares in respect ofwhich such deduction and withholding was made, provided that such withheld amounts areactually remitted to the appropriate taxing authority. To the extent that the amount so requiredor permitted to be deducted or withheld from any payment to a holder exceeds the cashportion of the consideration otherwise payable to the holder, HOC, CallCo, the Company andthe Transfer Agent are hereby authorized to sell or otherwise dispose of such portion ofconsideration on behalf of the holder of the Exchangeable Shares as is necessary to providesufficient funds to HOC, CallCo, DutchCo, the Company or the Transfer Agent, as the casemay 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 remitany unapplied balance of the net proceeds of such sale.(m) NoticesAny notice, request or other communication to be given to HOC by a holder of ExchangeableShares shall be in writing and shall be valid and effective if given by mail (postage prepaid) orby telecopy or by delivery to the registered office of HOC and addressed to the attention of thePresident. Any such notice, request or other communication, if given by mail, telecopy ordelivery, shall only be deemed to have been given and received upon actual receipt thereofby HOC.Any presentation and surrender by a holder of Exchangeable Shares to HOC or the TransferAgent of certificates representing Exchangeable Shares in connection with the liquidation,dissolution or winding-up of HOC or the retraction or redemption of Exchangeable Sharesshall be made by registered mail (postage prepaid) or by delivery to the registered office ofHOC 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 ofcertificates shall only be deemed to have been made and to be effective upon actual receiptthereof by HOC or the Transfer Agent, as the case may be. Any such presentation andsurrender of certificates made by registered mail shall be at the sole risk of the holder mailingthe same.Any notice, request or other communication to be given to a holder of Exchangeable Shares byor 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 registerof HOC or, in the event of the address of any such holder not being so recorded, then at thelast known address of such holder. Any such notice, request or other communication, if givenby mail, shall be deemed to have been given and received on the third Business Day followingthe date of mailing and, if given by delivery, shall be deemed to have been given and receivedon the date of delivery. Accidental failure or omission to give any notice, request or othercommunication to one or more holders of Exchangeable Shares shall not invalidate orotherwise alter or affect any action or proceeding to be taken by HOC pursuant thereto.7. DIRECTORS’ AND OTHERS’ INTERESTSShareholdings7.1 As at the date of this document, the Directors and the Senior Manager have no interests in theshare capital of the Company. The table below sets out the expected interests of the Directors275

(and of persons connected with them) and Senior Manager in the share capital of the Company asat Admission:Number of Percentage ofDirector/Senior Manager Ordinary Shares Issued Share CapitalMichael 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 0General Sir Michael Wilkes ......................... 0 0Brian Smith .................................... 0 0(1) Mr. Anthony Buckingham’s Ordinary Shares include the Ordinary Shares held by the Major Shareholder, a companyowned and controlled by Mr. Buckingham.The Directors are expected to be interested in 86,000,410 Ordinary Shares immediately followingAdmission. 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 pursuantto the Scheme (the terms of which are summarised in section 8 of this Part X):Number ofDirector/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$5.01Anthony 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$5.01Paul 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$5.01Gregory Turnbull ............ 600,000 20 May 2010; 150,000 Options at Cdn$.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$9.7014 December 2011 300,000 Options at C$29.1421 December 2012 150,000 Options at C$50.06Brian 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 theexchange 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 hasor will immediately following Admission have an interest which represents 3 per cent. or more of theissued voting share capital of the Company:Number of Percentage of IssuedShareholder Ordinary Shares Share CapitalMajor 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 whoeither as at the date of this document or immediately following Admission exercises, or couldexercise, 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 anyother holder of Ordinary Shares in respect of any Ordinary Share held by them.7.6 Service Contracts/Terms of EmploymentMr. Anthony Buckingham entered into an executive service agreement with the Company, dated28 March 2008, in which he agreed to act as Chief Executive Officer. The agreement is terminableon not less than 24 months’ written notice by the Company at any time or 6 months notice byMr. Buckingham at any time; in addition, the Company may terminate the agreement and makepayment in lieu of notice. Mr. Buckingham’s basic annual salary is £675,000 and he is eligible toreceive an annual performance-related bonus which will be determined at the discretion of theBoard. Mr. Buckingham has also been granted options under the Scheme. Mr. Buckingham isentitled 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 Companyfrom time to time. In the event of a change of control of the Company, if Mr. Buckingham resignsor 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 hisannual salary.Mr. Paul Atherton entered into an executive service agreement with the Company, dated28 March 2008, in which he agreed to act as Chief Financial Officer. The agreement is terminableon not less than 24 months’ written notice by the Company at any time or 6 months’ notice byMr. Atherton at any time, in addition, the Company may terminate the agreement and makepayment in lieu of notice. Mr. Atherton’s annual salary is £500,000 and he is eligible to receive anannual 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 thebenefits of private medical insurance, life insurance, an allowance in the amount of £77,500 andexecutive participation in the retirement and welfare benefit schemes of the Company from time totime. In the event of a change of control of the Company, if Mr. Atherton resigns or the Companyterminates his appointment within twenty-four months of such change of control, he shall beentitled to an immediate payment in lieu of notice of a sum equivalent to three times his annualsalary.Mr. Michael Hibberd, Mr. Gregory Turnbull, John McLeod and General Sir Michael Wilkes areengaged as non-executive directors of the Company under the letters of appointment dated28 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 otheramount as the board in its sole discretion deems appropriate) per day worked in excess of 20 daysper 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 earlytermination, Mr. Hibberd, Mr. Turnbull, Mr. McLeod and General Sir Michael Wilkes are each tobe appointed for an initial period of 2, 1, 1 and 3 years, respectively (and for a period of a further3 years after the initial term of their appointments). Mr. Hibberd and Mr. Turnbull are entitled to achange of control bonus (relating to a change of control in HOC) in the amount of $75,000 plus apro-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 apayment of £50,000 upon joining the board of the Company.All the directors (both executive and non-executive (excluding General Sir Michael Wilkes who isnot a director of HOC)) are entitled to a $75,000 payment in the event they are asked to resignfrom 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 theCompany 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 theDirectors 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 ordeferred compensation) and benefits in kind granted (under any description whatsoever) to each ofthe Directors and Senior Managers by members of the Group was:Remuneration Paid (Including ContingentDirector/Senior Manager or Deferred Compensation) Benefits in KindMichael Hibberd ..... Annual directors’ fee of Cdn$15,000; 90,000 HOC OptionsBonus 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 OptionsBonus of Cdn$34,989.Brian Smith ......... Annual salary of $304,908; 90,000 HOC OptionsBonus of $391,620.Other Interests7.9 The Directors and Senior Managers:(a) other than directorships of Group Companies the Directors, are or have been directors orpartners of the following companies and partnerships at any time in the previous five years:Position stillDirector/Senior Manager Position Company/Partnership held (yes/no)Michael Hibberd Director Iteration Energy Ltd. YesDirector AltaCanada Energy Corp. YesDirector Challenger Energy Corp. YesDirector Deer Creek Energy Ltd. NoDirector Fern Energy Ltd. YesChairman and CEO MJH Services Inc. YesDirector Pan Orient Energy Corp. YesDirector Rally Energy Corp. NoDirector Ramtelecom Inc. YesChairman and CEO Sunshine Oilsands Ltd. YesDirector Zapata Energy Corp. YesDirector 763846 Alberta Ltd. YesPaul Atherton Director SeaDragon Offshore Limited YesPartner Wallgrave Partnership NoDirector Plaza 107 Limited NoTrustee/Treasurer Royal School of Mines NoAssociation278

Position stillDirector/Senior Manager Position Company/Partnership held (yes/no)Gregory Turnbull Director Action Energy Inc. YesDirector BNP Resources Inc. YesDirector Castle Rock Petroleum Ltd. NoDirector Clearwater Energy Inc. YesDirector Crescent Point Energy Ltd. NoDirector Crescent Point Energy Trust YesDirector Flagship Energy Inc. YesDirector Flowing Energy Corp. NoDirector Mohave Exploration & YesProduction Inc.Director Rally Energy Corp. NoDirector Seaview Energy Inc. YesDirector Seventh Energy Ltd. NoDirector Storm Energy Ltd. NoOfficer Storm Exploration Inc. YesDirector Sunshine Oilsands Ltd. YesDirector Trimox Energy Inc. NoJohn McLeod Director, Chairman Consolidated Beacon YesResources Ltd.Director, President, California Oil & Gas YesCEOCorporationDirector Range Minerals Inc. NoDirector Highview Resources Ltd. NoDirector Paris Energy Inc. YesDirector Calstar Oil & Gas Ltd. NoDirector Tuscany Energy Ltd. YesDirector Diaz Resources Ltd. YesDirector Petroworth Resources Inc. NoDirector Keeper Resources Inc. YesDirector Castlerock Petroleum Ltd. NoGeneral Sir Michael Chairman Cyberview Technology Ltd. YesWilkesChairman of PegasusBridge Fund YesAdvisory Board Management LimitedChairman Britam Defence Ltd. YesNon-Executive Stanley Gibbons Group Ltd. YesDirectorDeputy Chairman C.I. Traders NoNon-Executive Tryco Ltd. YesDirectorChairman 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 inthe 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 regulatoryauthorities (including designated professional bodies) and have never been disqualified by acourt from acting as a director of a company or from acting in the management or conduct ofthe affairs of any company within the previous five years.7.10 Gregory Turnbull is a partner of McCarthy Tétrault LLP, a firm of solicitors which has advised theGroup as to Canadian law in respect of the application for Admission. McCarthy Tétrault LLP is arelated party of McCarthy Tétrault Registered Foreign Lawyers and Solicitors (together ‘‘McCarthyTétrault’’) which has advised the Group as to English law in respect of the application forAdmission. McCarthy Tétrault will receive fees from the Company in respect of their advice and willcontinue 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 7.10above, none of the Directors or Senior Managers have any potential conflicts of interests betweentheir 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 ismaterial to the Admission.8. SUMMARY OF THE COMPANY’S 2008 REPLACEMENT SHARE OPTION SCHEMEThe terms of the Scheme are as follows:(a) Purpose and ParticipationThe HOC Plan was originally implemented by HOC, and approved by the shareholders ofHOC and the TSX in 2004. As a result of the reorganisation of the Group in accordance withthe terms of the Arrangement, holders of HOC Options will exchange each outstanding optionto 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 thereorganisation, the Company has adopted the Scheme on 18 March 2008 which is in substanceand form substantially the same stock option plan as the HOC Plan. The purpose of theScheme is to act as a replacement to the HOC Plan and to honour the options originallygranted under the HOC Plan Options by granting holders of HOC Options the option topurchase Ordinary Shares. The Scheme will be administered by the Board. There shall be nofurther options granted under this Scheme.(b) Number of Shares Under the SchemeThe maximum number of Ordinary Shares that may be issued from time to time pursuant toOptions granted under the Scheme is that number required to replace the HOC Options thatwere granted under the HOC Plan and were still in existence prior to their cancellation, being24,545,340 Ordinary Shares.(c)Term and Termination; VestingThe Company will deliver to each optionholder an option agreement which will include a dateon which the Option expires. If such expiry date occurs during or within 10 days after the lastday of a close period (meaning any period during which a policy of the Company prevents aninsider from trading in the Ordinary Shares), the expiry date for the Option will be the last dayof such 10 day period.The Options may be subject to vesting periods, as were determined by the Directors at the timethe Options were granted and will be set out in the option agreements delivered to theoptionholders.If an optionholder dies, only the portion of the Option that is exercisable at the date of deathof the optionholder may be exercised by the personal representatives of the optionholderduring the period ending 6 months after the death of the optionholder, after which period allOptions terminate.If an optionholder resigns his or her office or employment, or an optionholder’s contract as aconsultant terminates at its normal termination date, only the portion of the Option that isexercisable at the termination date may be exercised by the optionholder during the periodending 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 constructivedismissal, or an optionholder’s contract as a consultant is terminated by the Company beforeits normal termination date without cause, only the portion of the Option that is exercisable atthe termination date may be exercised by the optionholder during the period ending 90 daysafter the termination date, after which period all Options expire.An Option will expire immediately upon the optionholder ceasing to be eligible for Optionsunder the Scheme as a result of being dismissed from his or her office or employment for causeor an optionholder’s contract as a consultant being terminated before its normal terminationdate for cause, including where a person eligible for Options resigns his or her office or280

employment or terminates his or her contract as a consultant after being requested to do so bythe Company as an alternative to being dismissed or terminated by the Company for cause.(d) Exercise PriceThe exercise price of each Option granted under the Scheme will be an amount determined bythe Directors that ensures the optionholders are put in substantially the same position theywere in prior to the Arrangement and the cancellation of the HOC Plan.(e)(f)(g)AssignmentAn 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.Exercise and Right to Postpone ExerciseAn optionholder (or the personal representative of a deceased optionholder) who wishes toexercise an Option may do so by delivering a notice to the Company specifying the number ofOrdinary 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 exerciseprice for the Ordinary Shares. An Option may not be exercised for less than 100 OrdinaryShares at any one time, except where a smaller number of Ordinary Shares remains exercisablepursuant to an Option, in which case the Option may be exercised for such smaller number atone time.Each optionholder, upon becoming entitled to exercise an Option to purchase Ordinary Sharesin accordance with his or her respective option agreement, shall thereafter be entitled toexercise the Option to purchase such Ordinary Shares at any time prior to the expiration orother termination of the option agreement or the option rights granted thereunder inaccordance with such agreement. Nothing in the Scheme or option agreements obligates anoptionholder to exercise an Option.Amendment, Termination and Approvals(i) The Directors may without the approval of the shareholders of the Company, at any timeand from time to time, amend, suspend or terminate the Scheme at any time, providedthat no such amendment, suspension or termination may be made without obtaining anyrequired approval of any regulatory authority or stock exchange or materially prejudicethe rights of any optionholder under any Option previously granted to the optionholderwithout the consent or deemed consent of the optionholder.(ii) Notwithstanding section (i) above, the Directors may not, without the approval of theshareholders of the Company, make amendments to the Scheme for any of the followingpurposes:A. to increase the maximum number of Ordinary Shares that may be issued pursuant toOptions 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 issuedpursuant to Options granted under the Scheme; andF. to amend the provisions of the section entitled ‘‘Amendment and Termination’’ ofthe Scheme.(iii) The Directors may, at any time and from time to time, without the approval of theshareholders 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 ofOptions granted to insiders, approval of the shareholders of the Company mustbe obtained;C. the Directors would have had the authority to initially grant the Option under theterms as so amended; andD. the consent or deemed consent of the optionholder is obtained if the amendmentwould materially prejudice the rights of the optionholder under the Option.9. PROPERTY, PLANT AND EQUIPMENTThe Group’s material tangible fixed assets, including leasehold properties are as follows:Freehold/Property Description Location Leasehold Owner/ Tenant Expiry of Term Current RentHead Office Jersey Rental BDO Alto TemporaryChannel AgreementIslandsGroup Technical Offices London, U.K. Leasehold Grosvenor West End 28 September 2129 £29,500 per annumProperties/Coatbridge EstatesLimitedCanadian Office Calgary Leasehold Consolidated Becon N/A Cdn$1,100 perResources/HOCmonthHead-office in the KRI Erbil Rental Mrs Golala Salah January 2009 $2,600 per monthAgreement Ahmad Ahawqi/Heritage Middle EastOperations office in the Sulymaniyah Rental Mr. Kameran Kader January 2009 $2,000 per monthKRIAgreement Ahmad/HeritageMiddle East10. MATERIAL CONTRACTSThe following are the only contracts (not being contracts entered into in the ordinary course ofbusiness) which have been entered into by member of the Group within two years immediatelypreceding the date of this document and which are, or may be, material or which have been enteredinto at any time by members of the Group and which contain any provision under which anymember of the Group has any obligation or entitlement which is, or may be, material to the Groupas at the date of this document:10.1 Arrangement AgreementOn 22 February 2008, HOC entered into an arrangement agreement with the Company, DutchCoand Alberta CallCo which provides for the reorganisation of the share capital of the HOC throughthe Plan of Arrangement pursuant to the Business Corporation Act (Alberta). The terms of theArrangement Agreement are set out in section 1 of Part IX of this document.10.2 Voting and Exchange Trust AgreementAlso in connection with the Arrangement Agreement, HOC entered into a voting and exchangetrust agreement with the Company, Alberta CallCo and the Trustee on 27 February 2008. Pursuantto the Voting and Exchange Trust Agreement, the Company will issue one Special Voting Share tothe Trustee for the benefit of the Beneficiaries. The Special Voting Share will have the number ofvotes, 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 areentitled to vote will be entitled to instruct the Trustee to exercise those votes attached to the SpecialVoting Share for each Exchangeable Share held by such Beneficiary or to obtain a proxy from theTrustee entitling the Beneficiary to vote directly, at the relevant meeting, the votes attached to theSpecial 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 Sharewill cease upon the exchange (whether by redemption, retraction or liquidation or through theExchange 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 theTrustee of the Exchange Right, upon HOC facing certain insolvency events, to require the Companyto purchase from each Beneficiary all or any part of the Exchangeable Shares held by theBeneficiary. The purchase price payable by the Company for each Exchangeable Share pursuant tothe Exchange Right shall be satisfied in full by the Company delivering to each Beneficiary oneOrdinary Share for each Exchangeable Share held by such Beneficiary plus, to the extent not paidby HOC, an additional amount equal to the full amount of all declared and unpaid dividends oneach 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 Votingand 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 AgreementIn connection with the Arrangement Agreement, HOC, the Company, DutchCo and AlbertaCallCo 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 HOCincluding, but not limited to, the following:(a) the Company will not declare or pay dividends on Ordinary Shares unless HOC is able todeclare and pay and simultaneously declares and pays, as the case may be, an equivalentdividend on the Exchangeable Shares;(b) the Company will advise HOC in advance of the declaration of any dividend by theCompany; and(c) the Company will take all actions and do all things reasonably necessary to enable and permitHOC 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 AlbertaCallCo of its right to purchase Exchangeable Shares that are the subject of a RetractionRequest and the exercise and the exercise by Alberta CallCo of its right to purchase allExchangeable Shares in the event of the a proposed liquidation, dissolution or winding upof HOC.The Company has agreed to take all such actions as are reasonably necessary to cause all OrdinaryShares deliverable in connection with Exchangeable Shares to be listed and posted for trading on allstock exchanges on which outstanding Ordinary Shares are listed. The Company has also agreed notto exercise any voting rights attached to the Exchangeable Shares owned by it or any of its affiliateson 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 ofcertain events, such as the liquidation, dissolution or winding up of HOC and the receipt of aRetraction Request.The Support Agreement shall continue until such time as no Exchangeable Shares are held by anyperson or entity other than the Company and its affiliates.10.4 Relationship AgreementOn 28 March 2008, the Company entered into a relationship agreement (the ‘‘RelationshipAgreement’’) with Anthony Buckingham and the Major Shareholder, governing the relationshipbetween the parties following Admission. At Admission, Mr Buckingham will own 33.2 per cent. ofthe voting rights attaching to the issued share capital of the Company following Admission, directlyand indirectly through the Major Shareholder. The Relationship Agreement is conditional on283

Admission taking place, and has been entered into to regulate certain aspects of the continuingrelationship between the parties to ensure compliance with the Listing Rules.Pursuant to the terms of the Relationship Agreement, Mr. Buckingham agrees to exercise allpowers of control, and procure (to the extent possible) that the Major Shareholder exercises allpowers of control, in relation to the Company so as to ensure that: (i) at all times each of theCompany and the other Group members is capable of carrying on, and does carry on, its businessindependently of Mr. Buckingham and the Major Shareholder and any of their associates, havingregard to the interests of the Group, rather than for the benefit of any particular shareholder orgroup of shareholders in the Company; (ii) at all times the business and affairs of the Companyshall be managed by the Board in accordance with the Articles and all applicable law and for thebenefit of its shareholders as a whole; (iii) all transactions and relationships between any Groupmember and the Major Shareholder or Mr. Buckingham, or any of their associates are conductedon arm’s length terms and on a commercial basis in compliance with the Listing Rules; (iv) therequirements relating to transactions with related parties set out in Listing Rule 11 are compliedwith in relation to transactions between Mr. Buckingham, the Major Shareholder or any of theirassociates on the one hand and the Group on the other hand; and (v) the terms of the RelationshipAgreement are complied with in all respects.All provisions of the Relationship Agreement are to remain in effect until the earlier of (i) whilstMr. Buckingham and the Major Shareholder continue to own in aggregate an amount of shares inthe Company representing no less than 25 per cent. of the rights attaching to the issued sharecapital 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 majorityof Directors who are independent of Mr. Buckingham, if the Board is comprised of fewer than sixdirectors, no more than one Director may not be independent of Mr. Buckingham and any of hisassociates. If the Board is comprised of more than six directors, no more than one-third of theDirectors may not be independent of Mr. Buckingham and his associates.Intra-group transfers are permitted by Mr. Buckingham or the Major Shareholder to any relatedundertakings, so long as any transferee agrees to be bound by the terms of the RelationshipAgreement. The agreement also contains confidentiality provisions, whereby Mr. Buckinghamagrees 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 confidentialall non-public information relating to the business, investments, finances and other matters of theGroup in accordance with his Service Agreement as if all such persons were bound by the provisionsof confidentiality in such agreement.10.5 Sponsor’s AgreementOn 28 March 2008, the Company, HOC, the Directors and the Sponsor entered into a SponsorAgreement, pursuant to which, inter alia:(a) each of the Company and HOC appointed JPMorgan Cazenove Limited as sponsor inconnection with the applications for Admission;(b) the Company confirmed that it had made all relevant applications to the FSA, the LSE, theJersey Financial Services Comission, TSX, and CRESTCO, in respect of Admission, andformal approval for this document and for Admission of all the Ordinary Shares and theExchangeable Shares to the Official List and to the LSE for the Admission of all the OrdinaryShares 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 JerseyFinancial Services Commission and CRESTCO, in respect of Admission, and formal approvalfor this document and for Admission of all the Exchangeable Shares to the Official List and tothe LSE for the Admission of all the Exchangeable Shares to trading on its main market forlisted securities;(d) the Company has agreed to pay the Sponsor a management fee of £1,000,000 plus VAT (ifapplicable) on Admission;(e) the obligations of the Sponsor are subject to customary conditions (including, amongst otherthings, Admission occurring). The Sponsor has the right to terminate the Sponsor Agreementprior to the expected date for Admission in certain circumstances that are typical for an284

agreement of this nature. These circumstances include the occurrence of certain materialadverse changes in the condition or the management, business affairs or business prospects ofthe 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 theSponsor and the Company and HOC have on a joint and several basis given certain indemnitiesto the Sponsor that are typical of an arrangement of this nature.10.6 Placing Agreement for 2007 Equity FinancingOn 14 November 2007, HOC completed an equity financing raising proceeds of Cdn$181.5 millionfrom the issue of 3,000,000 HOC Common Shares. As part of the same transaction, the MajorShareholder sold 3,000,000 HOC Common Shares that it held, reducing its interest from52 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 whichwere given by HOC and the Directors as to the accuracy of the information contained in the placingagreement and other matters relating to the HOC Common Shares, the Group and its business.10.7 Underwriting Agreement for the HOC Bond Private PlacementIn February 2007, HOC raised $165 million by completing a private placement of HOC Bonds. TheHOC Bonds were issued at par and have a maturity of 5 years. The coupon and yield to maturity are8 per cent. annually. HOC Bonds are convertible into HOC Common Shares at a price of $47 perHOC 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 withinterest coupons attached. The HOC Bonds and interest coupons constitute direct, unsubordinatedand unconditional obligations of HOC secured in the manner provided below and ranking paripassu and rateably without any preference among themselves.The obligations of HOC under the HOC Bonds are secured by a first fixed charge over all sumsstanding in credit to the escrow agreement (being the agreement whereby HOC deposited the sumof $19,836,663 in an escrow account) constituted by a security deed dated 16 February 2007 andmade 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 dividendpayment on the HOC Common Shares or make any other distributions to its shareholders nor shallit offer, purchase, redeem or otherwise acquire for consideration any HOC Common Shares, ineach case constituting on a consolidated basis more than 30 per cent. of the earnings of HOC forthe immediately preceding financial year; (2) the aggregate outstanding principal amount of allindebtedness for borrowed money raised by any person (but excluding any indebtedness forborrowed money raised by one member of the Group from another member of the Group) andbenefiting from any security interest given by HOC or any of its subsidiaries upon, or with respectto, or in respect of any company which for the time being holds an interest in, either the ZapadnoChumpasskoye licence or the licence relating to Block 1 and Block 3A, any assets used in thefurtherance of the activities permitted by these licences and any revenues derived from these twolicences shall not exceed $100,000,000 each; and (3) HOC will ensure that no indebtedness of HOCor any subsidiary and no guarantee by HOC or any subsidiary of any indebtedness of any person willbe secured by a security interest upon any of the present or future business, assets or revenues ofHOC 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 istaken) all necessary action to ensure that immediately upon completion of the Plan ofArrangement, at its option, either (a) the Company is substituted under the bonds as principaldebtor in place of HOC or becomes a guarantor under the bonds and, in either case, to makenecessary consequential amendments such that the bonds may be converted into or exchanged forOrdinary Shares; or (b) such amendments are made to the bonds such that the bonds may beconverted into or exchanged for Ordinary Shares.285

10.8 Facility AgreementsIn 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 isvariable at a rate of LIBOR plus 1.35 per cent. The loan, which is secured on the property, isscheduled to be repaid by 240 instalments of capital and interest at monthly intervals, subject to aresidual debt at the end of the term of the loan of no more than £1,860,000. HOC provided acorporate guarantee to the lender.In October 2007, a wholly-owned subsidiary of HOC received a loan of U.S.$9,450,000 to refinancethe acquisition of a private corporate jet delivered in 2007. Interest on the loan is variable at a rateof LIBOR plus 1.6 per cent. The loan, which is secured on the aircraft, is scheduled to be repaid by20 consecutive quarterly instalments of principal. Each instalment equals to US$117,500 with thefinal 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 ofthe Sanjawi work programme in Pakistan was provided by Standard Bank Jersey Limited on behalfof HOGL upon awarding of the Sanjawi licence. The cash-backed bank guarantee has a term until31 December 2010.In November 2006, a wholly-owned subsidiary of HOC received a loan of $200 million from HOGLfor exploration and development purposes in the Zapadno Chumpasskoye field as well as tosupport the operational and commercial activities of the subsidiary and other activities agreed inadvance by the parties. Interest on the loan is variable at a rate of LIBOR plus 4 per cent. The loanis 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 sharesin SeaDragon in favour of ABN AMRO and Lloyds TSB Bank plc. These charges were made tosupport an overdraft facility of $6 million for use by Gander Drilling Limited, a wholly-ownedsubsidiary of SeaDragon.11. TAXATION11.1 Taxation(a) United Kingdom Taxation(i) GeneralThe following information is based upon the tax legislation and tax authorities’ practicecurrently in force in the U.K. and Jersey. The comments are of a general nature only andare not a full description of all relevant tax considerations. The comments only apply topersons who are resident and (in the case of an individual) ordinarily resident in (and onlyin) the U.K. (except where express reference is made to the treatment ofnon-U.K. residents) and only apply to persons who hold their Ordinary Shares asinvestments and are the absolute beneficial owners of them. The information in both theU.K. and Jersey sections below is applicable to such investors and both sections should beread in conjunction with one another. The statements do not constitute advice to anyShareholder. Any person who is in any doubt as to his tax position, or who is subject to taxin a jurisdiction other than the U.K., should consult a professional adviser concerning histax position in respect of the acquisition, holding or disposal of Ordinary Shares.(ii) Tax ResidenceThe Company is incorporated in Jersey and currently conducts its affairs so that itsbusiness is centrally managed and controlled in Guernsey. This summary is prepared onthe assumption that its business will continue to be centrally managed and controlledin Guernsey.(iii) DividendsUnder current Jersey taxation legislation tax will not be withheld from dividends paid bythe Company. Under current U.K. taxation legislation no tax will be withheld fromdividends paid by the Company. Currently for U.K. tax purposes no tax credit wouldattach to any dividends paid by the Company. After 5 April 2008, U.K. tax law is expected286

to change. Where the Company pays a dividend to a holder of Ordinary Shares being anindividual resident in the U.K. (for the purposes of U.K. tax law) that person may beentitled to a tax credit in respect of the dividend received. These provisions are expectedto apply to an individual who owns less than 10 per cent. of the Ordinary Shares in theCompany provided that that individual receives less than £5,000 in dividends in any taxyear from companies which are not resident in the U.K. for tax purposes. The value of thetax credit is currently one ninth of the amount of the dividend received (or 10 per cent. ofthe aggregate of the amount of the dividend and tax credit). Such an individual will beliable 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 taxpurposes and will be subject to U.K. income tax at the special dividend rate of tax asdescribed below.Individuals who are not liable to income tax at a rate greater than basic rate (i.e. those whopay 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 suchindividual’s liability to pay income tax in respect of the gross dividend and there will be nofurther 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 bepayable on dividends at the ‘‘dividend upper rate’’ (currently 32.5 per cent.). The10 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, whentreated 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 thegross dividend income cannot reclaim payment of the tax credit from HM Revenueand Customs.Subject to certain exceptions, a corporate Shareholder which is resident for tax purposesin the U.K. is not liable to tax on a dividend paid by the Company to it and is not able toclaim repayment of the tax credit attaching to the dividend.(iv) Capital Gains TaxA disposal or deemed disposal of capital assets by a U.K. resident or ordinarily residentshareholder will give rise to either a chargeable gain or an allowable loss. Gains and lossesare calculated by deducting from the sale proceeds or, in some instances from the marketvalue of the time of disposal, the original cost and incidental costs of acquisition andincidental costs of disposal. Recipients within the charge to corporation tax may beentitled to an indexation allowance in computing a capital gain. Currently, a U.K. residentindividual or trustee may be entitled to taper relief in computing a capital gain or loss. It isexpected that taper relief will be abolished for disposals after 5 April 2008. U.K. residentindividuals or trustees may also be entitled to an annual allowance in arriving at theamount on which they are charged capital gains tax.A disposal or deemed disposal of a capital asset by a U.K. resident or ordinarily residentindividual 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 situatedoutside of the U.K. at the time of disposal. Where the asset is non-U.K. situated, gains willonly be taxed to the extent that the gains are (or are deemed to be) remitted to theU.K. As the Company is incorporated outside of the U.K., and as its principal register ismaintained outside of the U.K. it is expected that the Ordinary Shares will be deemed tobe non-U.K. situated for these purposes. Various changes to remittance basis are expectedto take place after 5 April 2008. An individual claiming the remittance basis may losecertain tax allowance and, in certain cases, an individual may be charged a flat rate sum ofmoney before the remittance basis can apply.If an individual ceases to be resident or ordinarily resident in the U.K. for a period of lessthan five years and disposes of the Ordinary Shares, in certain circumstances any gain onthat disposal may be liable to U.K. CGT upon that holder becoming once again resident orordinarily resident in the U.K.287

(v) Stamp Duty and Stamp Duty Reserve TaxThe following comments are intended as a guide to the general United Kingdom stampduty and stamp duty reserve tax position and do not relate to persons such as marketmakers, brokers, dealers, intermediaries and persons connected with voluntaryarrangements or clearance services, to whom special rules apply. No United Kingdomstamp 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 uncertificatedform, United Kingdom stamp duty (at a rate of 0.5 per cent. of the amount of the value ofthe consideration for the transfer rounded up to the nearest £5.00) is payable on anyinstrument of transfer of the Ordinary Shares executed within, or in certain cases broughtinto, the United Kingdom. Provided that the Ordinary Shares are not registered in anyregister of the Company kept in the United Kingdom, any agreement to transfer theOrdinary Shares will not be subject to United Kingdom stamp duty reserve tax.(vi) Jersey Taxation(a) Taxation of CompanyAs the Company’s business is centrally managed and controlled in Guernsey, theCompany will be regarded as not resident for Jersey tax purposes in Jersey. TheCompany will not be subject to Jersey income tax on income arising outside of Jerseyand by concession, on bank interest arising in Jersey. There is no obligation orentitlement 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 andlocally 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. TheCompany will be required to register for GST if its taxable supplies are greaterthan £300,000.Despite its business being centrally managed and controlled in Guernsey, theCompany will conduct its affairs so that it is outside the scope of Guernseyincome tax.(b) Tax implications for Jersey resident investorJersey resident shareholders in receipt of dividends from the Company will be subjectto 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 dividendprovisions which seek to tax Jersey resident shareholders on all or a proportion of theCompany’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 thetransfer inter vivos, exchange or repurchase of Ordinary Shares but there is a stampduty payable when Jersey Grants of Probate or Letters of Administration arerequired. Stamp duty is levied according to the size of the estate and in the case of anestate not exceeding £100,000 in value the sum payable would be £50 per £10,000 orpart thereof, and for estates above £100,000, £500 on the first £100,000 and £75 peradditional £10,000 or part thereof. There is no upper limit on stamp duty payable. Anapplication fee is also due to the registrar of Probate on all Grant applications, this ispresently £50. Under Jersey law, a Jersey Grant of Probate or Letters ofAdministration is required to transfer or redeem shares on the death of a Shareholderexcept where the total value of the deceased’s Jersey estate is less than £10,000 whenthe Directors of the Company may, at their discretion, dispense with this requirementon certain conditions being satisfied. If they do so, they may be indemnified againstclaims under the Probate (Jersey) Law 1998 if the deceased died domiciled withinspecific 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 otherthan 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 thetaxation of savings income in the form of interest payments, and in line with steps taken byother relevant third countries, Jersey introduced with effect from 1 July 2005 a retentiontax system in respect of payments of interest, or other similar income, made to anindividual beneficial owner resident in an EU Member State by a paying agent establishedin Jersey. The retention tax system applies for a transitional period prior to theimplementation of a system of automatic communication to EU Member States ofinformation regarding such payments. During this transitional period, such an individualbeneficial owner resident in an EU Member State will be entitled to request a payingagent not to retain tax from such payments but instead to apply a system by which thedetails of such payments are communicated to the tax authorities of the EU Member Statein which the beneficial owner is resident.The retention tax system in Jersey is implemented by means of bilateral agreements witheach of the EU Member States, the Taxation (Agreements with European Union MemberStates) (Jersey) Regulations 2005 and Guidance Notes issued by the Policy & ResourcesCommittee of the States of Jersey. Based on these provisions and our understanding of thecurrent practice of the Jersey tax authorities, any dividend distributions to shareholders bythe Company and income realised by shareholders upon the sale, refund or redemption ofshares do not constitute interest payment for the purpose of the retention tax andtherefore neither the Company nor any paying agent appointed by the Company in Jerseyis obliged to levy the retention tax in Jersey under those provisions in respect thereof. Tothe extent that the Company makes distributions in the form of interest in the future, theobligations set out above may apply.(c)Taxation Implications for a Canadian Resident InvestorTHIS SUMMARY IS OF A GENERAL NATURE ONLY AND IS NOT INTENDED TOBE, NOR SHOULD IT BE CONSTRUED TO BE, LEGAL, BUSINESS OR TAX ADVICETO ANY PARTICULAR SHAREHOLDER. CONSEQUENTLY SHAREHOLDERS AREURGED TO CONSULT THEIR OWN TAX ADVISORS FOR ADVICE AS TO THE TAXCONSEQUENCES OF AN INVESTMENT IN THE ORDINARY SHARES HAVINGREGARD TO THEIR PARTICULAR CIRCUMSTANCES.The following is a summary of the principal Canadian federal income tax considerations underthe ITA generally applicable to persons who, for purposes of the ITA, (i) are or are deemed tobe resident in Canada, (ii) hold Ordinary Shares as capital property, and (iii) deal at arm’slength with the Company and are not affiliated with the Company (‘‘Canadian Shareholder’’).Ordinary Shares will generally constitute capital property to the holder unless such personholds such securities in the course of carrying on a business, an adventure or concern in thenature 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 ‘‘specifiedfinancial institution’’, as defined in the ITA, (ii) an interest in which would be a ‘‘tax shelterinvestment’’, as defined in the ITA, or (iii) in respect to whom the Company is or will be aforeign affiliate within the meaning of the ITA. Such holders and those who do not hold theirOrdinary Shares as capital property should consult their own tax advisers regarding theirparticular 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 administrativepolicies and assessing practices of the CRA, all in effect as of the date hereof. This summaryalso takes into account all proposed amendments to the ITA publicly announced by or onbehalf of the Minister of Finance (Canada) prior to the date hereof (‘‘Tax Proposals’’), andassumes that all such Tax Proposals will be enacted substantially as proposed. However, noassurances 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 anddoes not otherwise take into account or anticipate any changes in law, administrative policy orassessing practice, whether by judicial, governmental or legislative action or decision, nor doesit take into account provincial, territorial or foreign income tax legislation or considerations,which may differ from the Canadian federal income tax considerations described herein. No289

advance income tax ruling has been sought or obtained from CRA to confirm the taxconsequences of any of the transactions described herein.This summary also assumes that the Company is and will remain a non-resident of Canada forthe purposes of the ITA.For the purposes of the ITA, all amounts relating to the acquisition, the holding and thedisposition of the Ordinary Shares, including dividends, adjusted cost base and proceeds ofdisposition must generally be determined in Canadian dollars at applicable exchange rates.(vii) Dividends on Ordinary SharesDividends received or deemed to be received on Ordinary Shares by a CanadianShareholder who is an individual will be required to be included in computing theCanadian Shareholder’s income for the purposes of the ITA and will not be subject to thegross up and dividend tax credit rules applicable to dividends received from taxableCanadian corporations under the ITA.Dividends received or deemed to be received on Ordinary Shares by a CanadianShareholder that is a corporation will be required to be included in computing theCanadian Shareholder’s income for purposes of the ITA and will generally not bedeductible in computing its taxable income.(viii) Disposition of Ordinary SharesCost Averaging of Identical PropertyThe ITA provides for a cost averaging rule for ‘‘identical properties’’, such as shares issuedby 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 otherproperties already held by the person, the person’s adjusted cost base of each identicalproperty will be equal to the quotient obtained when the aggregate of the adjusted costbases of all the identical properties previously held by the person and the cost of the newlyacquired identical property is divided by the number of all such identical properties held atthat time. Accordingly, at any time, the cost to a Canadian Shareholder of an OrdinaryShare will be averaged with the adjusted cost bases of any other Ordinary Shares held bythe Canadian Shareholder as capital property at that time.Acquisition and Disposition of Ordinary SharesA disposition or deemed disposition of Ordinary Shares (including on the purchase of theOrdinary Shares for cancellation by the Company) by a Canadian Shareholder willgenerally result in a capital gain (or capital loss) to the extent that the proceeds ofdisposition exceed (or are less than) the aggregate of the adjusted cost base to theCanadian Shareholder of the Ordinary Shares immediately before the disposition and anyreasonable cost of disposition.One half of any capital gain (the ‘‘taxable capital gain’’) realised by a CanadianShareholder will be included in its income for the year of disposition. One half of anycapital loss (the ‘‘allowable capital loss’’) realised by a Canadian Shareholder may bededucted by that person against taxable capital gains for the year of disposition subject toand in accordance with rules contained in the ITA. Any excess of allowable capital lossesover taxable capital gains for the year of disposition may be deducted in any of the threepreceding taxation years or carried forward indefinitely and deducted in any subsequenttaxation year against net taxable capital gains realised in such year to the extent andsubject to the limitations prescribed in the ITA. Any capital loss resulting from thedisposition of Ordinary Shares may, in certain circumstances, be reduced by the amount ofdividends previously received or deemed received on Ordinary Shares, to the extent andunder the circumstances described in the ITA. Capital gains realised by an individual ortrust, other than certain trusts, may give rise to alternative minimum tax under the ITA.(ix) Refundable TaxA Canadian Shareholder that is a ‘‘Canadian controlled private corporation’’ (as suchterm is defined in the ITA) may be liable to pay a refundable tax on certain investmentincome, including taxable capital gains and dividends paid on Ordinary Shares.290

(x) Foreign Property Information ReportingA Canadian Shareholder that is a ‘‘specified Canadian entity’’ for a taxation year or fiscalperiod and whose total cost amount of ‘‘specified foreign property’’ (which includes theOrdinary Shares) at any time in the year or fiscal period exceeds Cdn$100,000 will berequired to file an information return in respect of such property disclosing certaininformation including particulars of the Canadian Shareholder’s investment in suchproperty. Subject to certain exceptions, a Canadian Shareholder would be a specifiedCanadian entity. Such Canadian Shareholder holding specified foreign property shouldconsult their tax advisors in this respect.(xi) Proposed Legislation on Foreign Investment EntitiesOn 29 October 2007, Bill C-10 to amend the ITA, including proposals relating to foreigninvestment entities, was introduced in the House of Commons of Canada (‘‘FIELegislation’’). The proposed legislation, if enacted, would generally be applicable fortaxation years of taxpayers commencing after 2006. Canadian Shareholders should consulttheir own tax advisors regarding the potential application of these proposed rules in theirparticular circumstances.(xii) Eligibility for InvestmentThe Ordinary Shares, if and when listed on a designated stock exchange (which wouldinclude the LSE), will be qualified investments under the ITA for trusts governed byregistered retirement savings plans, registered retirement income funds, deferred profitsharing plans, registered disability savings plans and registered education savings plans.12. RELATED PARTY TRANSACTIONSSave as disclosed in the financial information in Part VII of this document at Note 24 and elsewherein this document, no members of the Group entered into related party transactions during thefinancial year ended 31 December 2006, or during the period between 1 January 2007 and the dateof this document.13. LITIGATIONMr. Micael Gulbenkian, a former chairman and CEO of HOC, who was dismissed on6 October 2006, has threatened legal action for wrongful dismissal and commenced arbitrationprocedures. The Group considers the likelihood of any successful claims as remote. As at the dateof 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 thatMr. Gulbenkian and his consulting company have or will invoke arbitration procedures based onarbitration clauses contained in agreements with the Group in respect of these allegations. TheDirectors do not know what the potential outcome of these claims will be and the Group will defendany action.Save as set out in the preceding paragraph, neither the Company nor any member of the Group isor has been involved in any governmental, legal or arbitration proceedings (including any suchproceedings which are pending or threatened of which the Company is aware) which may have, orhave had during the 12 months prior to the date of this document, a significant effect on theCompany and/or the Group’s financial position or profitability.The Directors are not aware of any environmental issues that may affect the Company’s utilisationof its tangible fixed assets.14. WORKING CAPITALThe Company is of the opinion that the Group has sufficient working capital for its presentrequirements, that is for at least the next 12 months from the date of this document.15. THE CITY CODEThe City Code will apply to the Company, and on Admission the Shareholders will be afforded theprotections provided by the City Code, in particular the mandatory takeover provisions in rule 9 ofthe City Code. In the event of a takeover, the squeeze-out provisions in articles 117 to 119 of the291

Act, would be available subject to, amongst other things, the offeror acquiring the requisitepercentage of the share capital to which the offer relates.16. CONSENTS16.1 KPMG LLP U.K. is a member firm of the Institute of Chartered Accountants of England and Walesand 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 andcontext in which they appear and has authorised the contents of those parts of this document whichcomprise 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 authorisedthose parts of this document which comprise its report, accepted responsibility for its report as partof this document and declared that it has taken all reasonable care to ensure that the informationcontained in that report is, to the best of its knowledge, in accordance with the facts and contains noomission likely to affect its import.17. SIGNIFICANT CHANGEThere has been no significant change in the financial or trading position of the Group since30 September 2007, the date to which the historical financial information in Section B of Part VII ofthis document has been prepared, save for an equity financing, raising gross proceeds ofCdn$181.5 million from the issue of 3 million HOC Common Shares, which completed on14 November 2007.18. MISCELLANEOUS18.1 The auditors of HOC from incorporation to the date of this document have been KPMG LLPCanada, chartered accountants, whose registered national office is Suite 3300, Commerce CourtWest, 199 Bay Street, Toronto, Ontario M5L 1B2, Canada and of the Company from incorporationto the date of this document have been KPMG LLP U.K., chartered accountants, whose registeredaddress 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 estimatedto 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 theCompany 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 ofthis document) no facts have been omitted which would render the reproduced informationinaccurate or misleading.18.4 The Ordinary Shares are created under the Act and are in registered form withISIN JE00B2Q4TN56. The Exchangeable Shares are created under the ABCA and are in registeredform with ISIN CA42969283053. The Ordinary Shares are in uncertificated form. Computershareacts 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 wholeor in part to the public in conjunction with the applications for the Ordinary Shares andExchangeable 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 ordealt with on any other exchange other than the London Stock Exchange. Other than the LondonStock Exchange, the Exchangeable Shares are also currently intended to be admitted to listing onthe TSX.18.7 There are no arrangements in existence under which future dividends are to be waived or agreed tobe waived.292

19. DOCUMENTS AVAILABLE FOR INSPECTIONCopies of the following documents will be available for inspection during normal business hours onany weekday (Saturday, Sundays and public holidays excepted) at the offices of McCarthy Tétrault,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 ended30 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 ofthis 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 2008293

PART XI—DEFINITIONSThe following definitions apply throughout this document, except in Part III of this document and Part VIIof this document, unless the context otherwise requires:‘‘ABCA’’the Business Corporations Act (Alberta), as amended‘‘Act’’‘‘Admission’’‘‘Aegis’’‘‘Affiliate’’‘‘Afren’’‘‘Alberta CallCo’’‘‘Articles’’‘‘Articles of HOC’’‘‘Arrangement Agreement’’‘‘Audit Committee’’‘‘Beneficiaries’’‘‘Board’’ or ‘‘Directors’’‘‘BRA’’‘‘Burren Energy’’‘‘Business Day’’‘‘CallCo Redemption Call Right’’the Companies (Jersey) Law 1991, and the regulationspromulgated thereunder as each may be amended from time totimeadmission of the Ordinary Shares and the Exchangeable Sharesto the Official List and to trading on the London StockExchange’s main market for listed securities becoming effectiveAegis Defence Services Ltd.has the meaning ascribed to such term in the ABCAAfren PCL1381890 Alberta ULC, a wholly owned subsidiary of DutchCoincorporated under the laws of Albertathe articles of association of the Companythe articles of association of HOC, as amendedthe agreement entered into in connection with the Plan ofArrangement between the Company, DutchCo and AlbertaCallCo on 22 February 2008 and described in section 1 ofPart IX of this documentthe audit committee of the Companythe registered holders (other than the Company and itsaffiliates) of the Exchangeable Sharesthe directors of the Company as at the date of this documentwhose names are set out on page 27 of this documentBougainvill Revolutionary ArmyBurren Energy PLCmeans any day on which commercial banks are generally openfor business in Jersey and Calgary, Alberta other than aSaturday, a Sunday or a day observed as a holiday in Jersey or inCalgary, Alberta under the laws of Canada or any jurisdictionthereinmeans the right, but not the obligation,(a) notwithstanding the right of the holders of ExchangeableShares to require HOC to redeem any or all of theirExchangeable Shares for Ordinary Shares, to purchaseExchangeable Shares that are the subject of a RetractionRequest for an amount per Exchangeable Share(the ‘‘Redemption Call Purchase Price’’) equal to theCurrent Market Price of an Ordinary Share on the lastBusiness Day prior to the Retraction Date which shall besatisfied in full by CallCo causing to be delivered to suchholder on Ordinary Share, plus to the extend not paid, anadditional amount equivalent to the full amount of all294

declared and unpaid dividends on each such ExchangeableShare held by such holder on any dividend record datewhich occurred prior to the Retraction Date;(b) notwithstanding the right of holders of ExchangeableShares to redeem all of the outstanding ExchangeableShares pursuant to the articles of the Exchangeable Shares,to purchase all but not less than all of the ExchangeableShares then outstanding in connection with a proposedredemption by HOC for the Redemption Call PurchasePrice on the Redemption Date, which shall be satisfied infull by CallCo causing to be delivered to such holder onOrdinary Share, plus to the extent not paid, an additionalamount equivalent to the full amount of all declared andunpaid dividends on each such Exchangeable Share held bysuch holder on any dividend and unpaid dividends on eachsuch Exchangeable Share held by such holder on anydividend record date which occurred prior to theRedemption Date, provided that, notwithstanding any otherprovision of the Plan of Arrangement, the ExchangeableShares that are subject to a Retraction Request may not bepurchased by CallCo if such Exchangeable Shares are heldby or on behalf of a Person in the United States or aU.S. Person‘‘Canadian Dollar Equivalent’’‘‘Canadian GAAP’’‘‘Canadian NationalInstrument 51-101’’‘‘Canadian person’’‘‘City Code’’‘‘CND’’‘‘Coatbridge’’‘‘Code of Conduct’’‘‘Combined Code’’means, in respect of an amount expressed in a currency otherthan Canadian dollars (the ‘‘Foreign Currency Amount’’) at anydate, the product obtained by multiplying (a) the ForeignCurrency Amount by (b) the noon spot exchange rate on suchdate for such foreign currency expressed in Canadian dollars asreported by the Bank of Canada or, in the event such spotexchange rate is not available, such exchange rate on such datefor such foreign currency expressed in Canadian dollars as maybe deemed by the board of directors of the Company to beappropriate for such purposeCanadian generally accepted accounting principlesNational Instrument 51-101 Oil & Gas Disclosure Standards ofthe Canadian Securities Administratorsany individual who is a resident of Canada or any Company,partnership or other entity created or organised in or under thelaws of Canada and any estate or trust the income of which issubject to Canadian federal income taxation regardless of itssourcethe City Code on Takeovers and Mergers issued by the Panel onTakeovers and MergersChumpassNefteDobychaCoatbridge Estates Limitedthe code of business conduct and ethics of the Companythe Combined Code on Corporate Governance published inJune 2006 by the Financial Reporting Council being the keysource of corporate governance recommendations forcompanies listed on the Official List295

‘‘Companies Act’’‘‘Company’’‘‘Company Control Transaction’’‘‘Company Dividend DeclarationDate’’‘‘Computershare’’‘‘Computershare Canada’’‘‘Congo’’‘‘Corporate Governance Committee’’‘‘CREST’’‘‘CRESTCO’’‘‘Court Hearing’’‘‘Court Meeting’’‘‘Current Market Price’’‘‘DRC’’‘‘DRC PSC’’the U.K. Companies Act 1985, as amendedHeritage Oil Limited a company incorporated in Jersey on6 February 2008 with Company number 99922 and whoseregistered address is Ordnance House, 31 Pier Road, St Helier,Jersey JE4 8PW Channel Islandsmeans any merger, amalgamation, tender offer, take-over bid,scheme of arrangement, material sale of shares (including amaterial sale of the shares of CallCo held by DutchCo) or rightsor interests therein or thereto or similar transactions involvingthe Company, or any proposal to do so that upon completion,does or would materially affect control of the Companymeans the date on which the board of directors of the Companydeclares any dividend on the Ordinary SharesComputershare Investor Services (Channel Islands) Limitedmeans Computershare Trust Company of Canadathe Republic of Congothe corporate governance committee of the Companythe computerised settlement system operated by CRESTCoLimited to facilitate the transfer of title to shares inuncertificated formEuroclear U.K. and Ireland Limitedthe Alberta provincial court hearing to be held in connectionwith the Plan of Arrangementthe meeting of the shareholders of the HOC Common Shares tobe convened in accordance with Plan of Arrangementmeans, in respect of an Ordinary Share on any date, theCanadian Dollar Equivalent of the average closing prices of theOrdinary Shares during a period of 20 consecutive trading daysending not more than three trading days before such date on theLSE or, if the Ordinary Shares are not then listed on the LSE,on such stock exchange or automated quotation system on whichthe Ordinary Shares are listed or quoted, as the case may be, asmay be selected by the board of directors of the Company forsuch purpose; provided, however, that if in the opinion of theboard of directors of the Company the public distribution ortrading activity of the Ordinary Shares during such period doesnot create a market which reflects the fair market value of theOrdinary Shares then the Current Market Price of the OrdinaryShares shall be determined by the board of directors of theCompany, in good faith and in its sole discretion, and providedfurther that any such selection, opinion or determination by theboard of directors of the Company shall be conclusiveand bindingthe Democratic Republic of Congothe production sharing contract entered into between thegovernment of the DRC and the Group in July 2006 in respectof the exploration and development work on Blocks 1 and 2296

‘‘DTR’’‘‘DutchCo’’‘‘ECOMOG’’‘‘ECOWAS’’‘‘EU’’‘‘E&E’’‘‘Eagle’’‘‘Eagle Drill’’‘‘Effective Date’’‘‘Effective Date’’‘‘Exchangeable Right’’‘‘Exchangeable Shareholders’’‘‘Exchangeable Shares’’‘‘Exchangeable Share Voting Event’’‘‘Exempt Exchangeable Share VotingEvent’’‘‘Extraordinary General Meeting’’ or‘‘EGM’’‘‘FSA’’ or ‘‘Financial ServicesAuthority’’‘‘FSMA’’‘‘Gazprom’’the Disclosure and Transparency Rules published by the FSAfrom time to timeHeritage Oil Coöperatief U.A., a wholly owned subsidiary of theCompany incorporated under the laws of the NetherlandsEconomic Community of West African States Monitoring GroupEconomic Community of West Africa Statesthe European Unionexploration and evaluation costsEagle Energy (Oman) LimitedEagle Drill Limiteddate upon which the Plan of Arrangement becomes effectiveupon the filing of the Articles of HOCmeans the date shown on the certificate issued pursuant tosection 193(11) of the ABCAthe right, upon HOC facing certain insolvency events, to requirethe Company to purchase from each Beneficiary all or any partof the Exchangeable Shares held by the Beneficiarythe registered holders of Exchangeable Sharesthe exchangeable shares of HOC the terms of which are set outat Part IX of this documentmeans any matter in respect of which holders of ExchangeableShares 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 whichholders of Exchangeable Shares are entitled to vote (or instructthe Trustee to vote) in their capacity as Beneficiaries under(and as that term is defined in) the Voting and Exchange TrustAgreementmeans any matter in respect of which holders of ExchangeableShares are entitled to vote as holders of Exchangeable Shares inorder to approve or disapprove, as applicable, any change to, orin the rights of the holders of, the Exchangeable Shares, wherethe approval or disapproval, as applicable, of such change wouldbe required to maintain the economic equivalence of theExchangeable Shares and the Ordinary Sharesthe extraordinary general meeting of HOC that was held on20 March 2008 in connection with the Plan of Arrangementthe Financial Services Authority in its capacity as the competentauthority for the purposes of Part VI of FSMA and in theexercise of its functions in respect of admission to the OfficialList otherwise than in accordance with Part VI of FSMAthe Financial Services and Markets Act 2000 of England andWales, as amendedJSC Gazprom297

‘‘Governmental Entity’’means any:(a) federal, provincial, state, territorial, regional, municipal,local or other government, governmental or publicdepartment, court, tribunal, arbitral body, commission,board or agency having jurisdiction over the Company orHOC as applicable;(b) any subdivision, agent, commission, board or authority ofany of the foregoing; or(c)any quasi governmental or private body exercising anyregulatory, expropriatory or taxing authority under or forthe account of any of the foregoing‘‘Group’’‘‘Heritage Austria’’‘‘Heritage Barbados’’‘‘Heritage DRC’’‘‘Heritage Holdings’’‘‘Heritage International Holding’’‘‘Heritage Middle East’’‘‘Heritage Security holders’’‘‘Heritage Switzerland’’‘‘HOC’’ or ‘‘Corporation’’‘‘HOC Board of Directors’’‘‘HOC Bonds’’‘‘HOC Common Shares’’‘‘HOC Option’’‘‘HOC Plan’’ or ‘‘HOC Stock OptionPlan’’‘‘HOGL’’‘‘holder’’‘‘IFRS’’the Company and its subsidiary companies set out in section 3 ofPart X of this documentHeritage Oil & Gas (Austria) GesmbHHeritage Oil (Barbados) LimitedHeritage DRC LimitedHeritage Oil & Gas Holdings LimitedHeritage International Holding GesmbHHeritage Energy Middle East Limitedholders of HOC Common Shares and holders of HOC OptionsHeritage Oil & Gas (Switzerland) SAHeritage Oil Corporation, a company incorporated under thelaws of Alberta whose shares are expected to be owned byDutchCo (a wholly owned subsidiary of the Company) and theExchangeable Shareholders immediately following thecompletion of the HOC Subscriptionmeans the board of directors of HOCthe issued and outstanding convertible bonds in HOC dated16 February 2007the common shares of HOC, the terms of which are set out atPart IX of this documentan issued and outstanding option to acquire HOC CommonShares pursuant to the HOC Stock Option Planthe stock option plan of HOC approved by HOC Shareholdersin 2004 and the new stock option plan approved byHOC Shareholders in 2007Heritage Oil & Gas Limitedmeans, when used in reference to the Exchangeable Shares, theholders of Exchangeable Shares from time to time in the registermaintained by and on behalf of HOC in respect of theExchangeable SharesInternational Financial Reporting Standards298

‘‘ISIN’’‘‘ITA’’‘‘KRI’’‘‘KRG’’‘‘LIBOR’’‘‘Liquidation Call Right’’‘‘Listing Rules’’‘‘London Stock Exchange’’ or ‘‘LSE’’‘‘Major Shareholder’’‘‘Maurel et Prom’’‘‘Memorandum’’‘‘Naturalay Technologies’’‘‘New Companies Act’’‘‘Normal Course Issuer Bid’’‘‘NGK’’‘‘Official List’’‘‘Oman’’International Security Identification NumberIncome Taxes Act (Canada)the Kurdistan Region of Iraqthe Kurdistan Regional GovernmentLondon Interbank Offered Ratemeans the overriding right given to CallCo, in the event of andnotwithstanding the proposed liquidation, dissolution orwinding-up of HOC or any other distribution of the assets ofHOC among its shareholders for the purpose of winding up itsaffairs pursuant to the articles of HOC dealing with theExchangeable Shares, to purchase from all but not less than allof the holders of Exchangeable Shares (other than the Companyor any holder of Exchangeable Shares which is an Affiliate of theCompany) on the effective date of such liquidation, dissolution,winding-up or other distribution (the ‘‘Heritage LiquidationDate’’) all but not less than all of the Exchangeable Shares heldby such holders on payment by CallCo of an amount perExchangeable Share (the ‘‘Liquidate Call Purchase Price’’)equal to the Current Market Price of Ordinary Shares on thelast Business Day prior to the Heritage Liquidation Date whichshall be satisfied in full by CallCo causing to be delivered to suchholder, one Ordinary Share; plus, to the extent not paid byHOC, an additional amount equivalent to the full amount of alldeclared and unpaid dividends on each such ExchangeableShare on any dividend record date which occurred prior to theHeritage Liquidation Date. In the event of the exercise of theLiquidation Call Right by CallCo, each holder shall be obligatedto sell all the Exchangeable Shares held by the holder to CallCoon the Heritage Liquidation Date on payment by CallCo to theholder of the Liquidation Call Purchase Price for each suchshare. and HOC shall have no obligation to pay the HeritageLiquidation Amount to the holders of such Exchangeable Sharesor otherwise redeem such shares so purchased by CallCothe listing rules of the Financial Services AuthorityLondon Stock Exchange plcAlbion Energy Limited, a company incorporated under the lawsof the Commonwealth of BarbadosEtablissements Maurel et Promthe memorandum of association of the CompanyNaturalay Technologies Limitedthe U.K. Companies Act 2006, as amendedthe action of a Canadian incorporated Company buying back itsown outstanding shares from the markets so it may cancel themNeftyanaya Geologicheskaya Kompaniyathe Official List of the Financial Services Authoritythe Sultanate of Oman299

‘‘Option’’‘‘Ordinary Shares’’‘‘PNG’’‘‘Pakistan’’‘‘Participating CanadianShareholders’’an option to acquire Ordinary Shares pursuant to the Schemeordinary shares of no par value in the capital of the CompanyPapua New Guineathe Islamic Republic of Pakistanthe shareholders of HOC who have elected to receiveExchangeable Shares in return for their shareholding in HOC inconnection with the Plan of Arrangement‘‘Person’’ includes an individual, sole proprietorship, partnership,unincorporated association, unincorporated syndicate,unincorporated organization, trust, body corporate, a naturalperson in his capacity as trustee, executor, administrator, orother legal representative and a Governmental Entity or anyagency or instrumentality thereof‘‘Pipelay’’‘‘Plan of Arrangement’’‘‘PRMS’’‘‘Prospectus Directive’’‘‘Prospectus Rules’’‘‘PSC’’ or PSA’’‘‘RAK Petroleum’’‘‘Ranger’’‘‘Redemption Date’’Natural Pipelay Worldwide Limitedthe court approved reorganisation of the share capital of HOC,pursuant to Article 193 of the ABCA where all of the existingHOC Common Shares were converted to Ordinary Shares andExchangeable SharesSPE/WPC/AAPG/SPEE 2007 Petroleum Resource ManagementSystemEU Prospectus Directive (2003/71/EC)the rules made for the purposes of Part VI of FSMA in relationto offers of securities to the public and admission of securities totrading on a regulated marketproduction sharing contract or production sharing agreementRAK Petroleum PCLRanger Oil Limitedmeans the date, if any, established by the HOC Board ofDirectors for the redemption by HOC of all but not less than allof the outstanding Exchangeable Shares pursuant to the Articlesof HOC, which date shall be no earlier than the seventhanniversary of the Effective Date, unless:(a) there are fewer than 10 per cent. of the number ofExchangeable Shares issued on the Effective Dateoutstanding (other than Exchangeable Shares held by theCompany and its Affiliates and as such number of sharesmay be adjusted as deemed appropriate by the HOC boardof directors to give effect to any subdivision orconsolidation of or stock dividend on the ExchangeableShares, any issue or distribution of rights to acquireExchangeable Shares or securities exchangeable for orconvertible into Exchangeable Shares, any issue ordistribution of other securities or rights or evidences ofindebtedness or assets, or any other capital reorganisationor other transaction affecting the Exchangeable Shares), inwhich case the HOC board of directors may accelerate suchredemption date to such date prior to the seventh300

anniversary of the Effective Date as they may determine,upon at least 60 days’ prior written notice to the registeredholders of the Exchangeable Shares;(b) a Company Control Transaction occurs, in which case,provided that the HOC board of directors determines ingood faith in its sole discretion that it is not reasonablypracticable to substantially replicate the terms andconditions of the Exchangeable Shares in connection withsuch Company Control Transaction and that theredemption of all but not less than all of the outstandingExchangeable Shares is necessary to enable the completionof such Company Control Transaction in accordance withits terms, the HOC board of directors may accelerate suchredemption date to such date prior to the seventhanniversary of the Effective Date as they may determine,upon such number of days prior written notice to theregistered holders of the Exchangeable Shares as the HOCboard of directors may determine to be reasonablypracticable in such circumstances;(c)an Exchangeable Share Voting Event is proposed, in whichcase, provided that the HOC board of directors determines,in good faith and in its sole discretion, that it is notreasonably practicable to accomplish the business purposeintended by the Exchangeable Share Voting Event (whichbusiness purpose must be bona fide and not for the primarypurpose of causing the occurrence of a Redemption Date),in any other commercially reasonable manner that does notresult in an Exchangeable Share Voting Event, theredemption date shall be the Business Day prior to therecord date for any meeting of the holders of theExchangeable Shares to consider the Exchangeable ShareVoting Event and the HOC board of directors shall givesuch number of days’ prior written notice of suchredemption to the registered holders of the ExchangeableShares as the HOC board of directors may determine to bereasonably practicable in such circumstances; or(d) an Exempt Exchangeable Share Voting Event is proposedand the holders of the Exchangeable Shares fail to take thenecessary action at a meeting of holders of ExchangeableShares, to approve or disapprove, as applicable, the ExemptExchangeable Share Voting Event, in which case theredemption date shall be the Business Day followingthe day of such meeting on which the holders of theExchangeable Shares failed to take such action andthe HOC board of directors shall give such number of days’prior written notice of such redemption to the registeredholders of the Exchangeable Shares as the HOC board ofdirectors may determine to be reasonably practicable insuch circumstances,provided, however, that the accidental failure or omission to giveany notice of redemption under clauses (a), (b), (c) or (d) aboveto the holders of Exchangeable Shares shall not affect thevalidity of any such redemption.‘‘Regulations’’ Companies (Uncertificated Securities) (Jersey) Order 1999301

‘‘Relationship Agreement’’‘‘Remuneration Committee’’means an agreement entered into between the Company,Anthony Buckingham and the Major Shareholder dated28 March 2008 described in section 10.4 of Part X of thisdocument;the remuneration committee of the Company‘‘Replacement Stock Option Scheme’’ the Company’s stock option scheme dated 18 March 2008or ‘‘Scheme’’‘‘Reporting Accountants’’‘‘Responsible Persons’’‘‘Reserves Data’’‘‘Retraction Request’’‘‘RUF’’‘‘ROWAL’’‘‘RPS’’‘‘RPS Report’’ or ‘‘Technical Report’’‘‘SEC’’‘‘SEDAR’’‘‘Seadragon’’‘‘Securities Act’’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 Canadathe Company and the Directorsthe proved, probable and possible reserves volumes and relatedestimated future net revenue values attributable to the Companyas evaluated by RPS and based on reserves information suppliedby the Company to RPSrequest by a holder of Exchangeable Shares for redemption ofsuch Exchangeable SharesRevolutionary United FrontRanger Oil West Africa LimitedRPS Energythe mineral experts report setting out the Group’s statement ofreserves data and other oil and gas information effective30 September 2007, prepared in accordance with PRMS andreproduced in its entirety at Part III of this documentthe U.S. Securities and Exchange Commissionthe Canadian System for Electronic Document Analysis andRetrievalSeaDragon Offshore Limitedthe United States Securities Act of 1933, as amended‘‘Senior Manager’’ the manager of the Company whose name is set out in section 1of Part II of this document‘‘Shareholders’’‘‘Sonangol’’‘‘Special Voting Share’’‘‘Sponsor’’‘‘Sponsor Agreement’’holders of Ordinary Shares or the holder of the Special VotingShare from time to timeSociedad Nacional de Combustíveis de Angola — Sonangol,U.E.E.the Special Voting Share in the Company to be issued to theTrusteeJPMorgan Cazenove Limited, in its capacity as sponsor to theCompanythe agreement entered into on 28 March 2008 between theDirectors, the Company, the Sponsor and HOC described insection 10.5 of Part X of this document302

‘‘Support Agreement’’‘‘Transfer Agent’’‘‘Trustee’’‘‘TNK-BP’’‘‘TSX’’‘‘Tullow’’‘‘Uganda’’‘‘U.K.’’ or ‘‘United Kingdom’’‘‘UNITA’’‘‘U.S.’’ or ‘‘United States’’‘‘U.S. Person’’‘‘Voting and Exchange Trust’’the agreement entered into on 17 March 2008 between theCompany, DutchCo, Alberta CallCo and HOC described insection 10.3 of Part X of this documentmeans Computershare Trust Company of Canada or such otherperson as may from time to time be appointed by HOC as theregistrar and transfer agent for the Exchangeable Sharesmeans Computershare Canada and, subject to the provisions ofArticle 9 of the Voting and Exchange Trust Agreement, includesany successor trusteeTyumenskaia Neftanaia Companiyathe Toronto Stock ExchangeTullow Oil PLCthe Republic of Ugandathe United Kingdom of Great Britain and Northern IrelandNational Union for the Total Independence of Angolathe United States of America, its territories and possessions, anystate of the United States of America and the District ofColumbia and all other areas subject to its jurisdictionhas the meaning ascribed to such term in Regulation S of theSecurities Act, as amendedan agreement entered into among the Company, HOC, AlbertaCallCo and the Trustee substantially in the form of Schedule 4 tothe Arrangement Agreement‘‘Voting and Exchange Trusta voting and exchange trust agreement entered into by theAgreement’’ Company, HOC Alberta CallCo and the Trustee, on27 February 2008, the terms of which are set out in section 10.2of Part X of this document‘‘Voting Rights’’‘‘C$’’ or ‘‘Canadian Dollars’’ or‘‘Cdn’’the right to receive notice of, attend (in person or by proxy or bycorporate representative), speak (in person or by corporaterepresentative) and to cast (in person or by proxy or bycorporate representative) one vote per share on a poll vote, orone vote per Shareholder on a show of hands, at generalmeetings of the Company, whether available to a Shareholder byvirtue of a holding of Ordinary Shares or the SpecialVoting Sharethe lawful currency of Canada‘‘£’’ or ‘‘Pounds Sterling’’ the lawful currency of the U.K.‘‘$’’, ‘‘U.S.$’’ ‘‘US$’’ or ‘‘Dollars’’ the lawful currency of the U.S.‘‘Chf’’ or ‘‘Swiss Franc’’‘‘RR’’ or ‘‘Russian Rouble’’the lawful currency of Switzerlandthe lawful currency of Russia303

PART XII—GLOSSARYThe following definitions apply throughout this document, unless the context otherwise requires:‘‘API’’a specific gravity scale developed by the American PetroleumInstitute for measuring the relative density of various petroleumliquids, expressed in degrees‘‘bbl’’‘‘bbls’’‘‘bbls/d’’ or ‘‘bopd’’‘‘Bcf’’barrelbarrelsbarrels per daybillion cubic feet‘‘boe’’ barrels of oil equivalent (1)‘‘boe/d’’ or ‘‘boepd’’‘‘condensate’’‘‘Gj’’‘‘LPG’’‘‘m 3 ’’‘‘Mbbls’’‘‘MMbbls’’‘‘Mboe’’‘‘MMboe’’‘‘Mcf’’‘‘Mcf/d’’‘‘MMBtu’’‘‘MMcf’’‘‘MMcf/d’’‘‘MMstb’’‘‘NGLs’’‘‘Petroleum’’‘‘Possible Reserves’’‘‘Probable Reserves’’barrels of oil equivalent per daylow density, high API hydrocarbon liquids that are present innatural gas fields where it condensates out of the raw gas if thetemperature is reduced to below the hydrocarbon dew pointtemperature of the raw gasgigajoulesliquid petroleum gascubic metresthousand barrelsmillion barrelsthousands of barrels of oil equivalentmillions of barrels of oil equivalentthousand cubic feetthousand cubic feet per daymillion British thermal unitsmillion cubic feetmillion cubic feet per daymillion stock tank barrelsnatural gas liquidsany mineral, oil or relative hydrocarbon (including condensateand natural gas liquids) and natural gas existing in its naturalcondition in strata (but not including coal or bituminous shale orother stratified deposits from which oil can be extracted bydestructive distillation)those additional reserves that are less certain to be recoveredthan Probable Reserves. It is unlikely that the actual remainingquantities recovered will exceed the sum of the estimatedProved plus Probable plus Possible Reservesthose additional reserves that are less certain to be recoveredthan Proved Reserves. It is equally likely that the actual304

emaining quantities recovered will be greater or less than thesum of the estimated Proved plus Probable Reserves‘‘Proved Reserves’’‘‘psi’’‘‘psia’’‘‘SPE’’‘‘WPC’’‘‘WTI’’those reserves that can be estimated with a high degree ofcertainty to be recoverable. It is likely that the actual remainingquantities recovered will exceed the estimated Proved Reservespounds per square inchpounds per square inch absoluteSociety of Petroleum EngineersWorld Petroleum CouncilWest Texas IntermediateNote (1): Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl isbased on an energy equivalency conversion method primarily applicable at the burner tip and does notrepresent a value equivalency at the wellhead.CONVERSIONThe following table sets forth standard conversions from Standard Imperial Units to the InternationalSystem of Units (or metric units).To Convert From To Multiply Byboes Mcfs 6Mcf m 3 28.174m 3 Cubic feet 35.494bbls m 3 0.159m 3 bbls oil 6.290Feet Metres 0.305Metres Feet 3.281Miles Kilometres 1.609Kilometres Miles 0.621Acres Hectares 0.405Hectares (Saskatchewan) Acres 2.471Hectares (Alberta) Acres 2.500305