-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, C9HbbEh/awtEGzk9M9KwkyqnN6inN1NJJf9HKfX8en+pBQCReTxZi8pf4KOTZxzp gUPsnjhPTeDrXdERtWhlTQ== 0000950142-04-001395.txt : 20040423 0000950142-04-001395.hdr.sgml : 20040423 20040423153028 ACCESSION NUMBER: 0000950142-04-001395 CONFORMED SUBMISSION TYPE: 40-F PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20040423 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CANADIAN NATURAL RESOURCES LTD CENTRAL INDEX KEY: 0001017413 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 FILING VALUES: FORM TYPE: 40-F SEC ACT: 1934 Act SEC FILE NUMBER: 333-12138 FILM NUMBER: 04750984 BUSINESS ADDRESS: STREET 1: 2000 STREET 2: 425 1ST ST CITY: S W CALGARY ALBERTA STATE: A0 ZIP: 00000 MAIL ADDRESS: STREET 1: 2500 855 2 ST NW CITY: CALGARY ALBERTA CANADA STATE: A0 ZIP: 9999999999 40-F 1 form40f_2003.txt FORM 40-F ANNUAL REPORT UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 40-F [_] Registration Statement pursuant to section 12 of the Securities Exchange Act of 1934 [X] Annual report pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2003 Commission File Number: 1-8795 CANADIAN NATURAL RESOURCES LIMITED (Exact name of Registrant as specified in its charter) ALBERTA (Province or other jurisdiction of incorporation or organization) 1311 (Primary Standard Industrial Classification Code Numbers) NOT APPLICABLE (I.R.S. Employer Identification Number (if applicable)) 2500, 855-2ND STREET S.W., CALGARY, ALBERTA, CANADA, T2P 4J8 TELEPHONE: (403) 517-7345 (Address and telephone number of Registrant's principal executive offices) CT CORPORATION SYSTEM, 111-8TH AVENUE, NEW YORK, NEW YORK 10011 (212) 894-8940 (Name, address (including zip code) and telephone number (including area code) of agent for service in the United States) SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: TITLE OF EACH CLASS: NAME OF EACH EXCHANGE ON WHICH REGISTERED: Common Shares, no par value New York Exchange Common Shares, no par value Toronto Stock Exchange SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: TITLE OF EACH CLASS: None SECURITIES FOR WHICH THERE IS A REPORTING OBLIGATION PURSUANT TO SECTION 15(D) OF THE ACT: None FOR ANNUAL REPORTS, INDICATE BY CHECK MARK THE INFORMATION FILED WITH THIS FORM: [X] Annual information form [X] Audited annual financial statements NUMBER OF OUTSTANDING SHARES OF EACH OF THE ISSUER'S CLASSES OF CAPITAL OR COMMON STOCK AS OF THE CLOSE OF THE PERIOD COVERED BY THE ANNUAL REPORT. 133,731,416 Common Shares outstanding as of December 31, 2003 Indicate by check mark whether the Registrant is furnishing the information contained in this Form to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the filing number assigned to the Registrant in connection with such Rule. Yes [_] No [X] Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] This Annual Report on Form 40-F shall be incorporated by reference into, or as an exhibit to, as applicable, the registrant's Registration Statement on Form F-9 (Registration No. 333-104919) under the Securities Act of 1933. PRINCIPAL DOCUMENTS - ------------------- The following documents have been filed as part of this Annual Report on Form 40-F: A. ANNUAL INFORMATION FORM For the Annual Information Form of Canadian Natural Resources Limited ("CNRL") for the year ended December 31, 2003, see Exhibit 1 of this Annual Report on Form 40-F. B. AUDITED ANNUAL FINANCIAL STATEMENTS For CNRL's consolidated audited financial statements for the year ended December 31, 2003 and 2002, including the auditor's report with respect thereto, see Exhibit 2 of this Annual Report on Form 40-F. For a reconciliation of important differences between Canadian and United States generally accepted accounting principles, see Note 16 of the Notes to the Consolidated Financial Statements. C. MANAGEMENT'S DISCUSSION AND ANALYSIS For CNRL's Management's Discussion and Analysis for the year ended December 31, 2003, see Exhibit 3 of this Annual Report on Form 40-F. D. SUPPLEMENTARY OIL & GAS INFORMATION For CNRL's Supplementary Oil & Gas Information for the year ended December 31, 2003, see Exhibit 4 of this Annual Report on Form 40-F. CONTROLS AND PROCEDURES - ----------------------- CNRL maintains disclosure controls and other procedures and internal control over financial reporting designed to ensure that information required to be disclosed in the reports filed under the Exchange Act, as amended, is recorded, processed, summarized and reported within the time periods specified in the Commission's rules and forms. CNRL's principal executive and financial officers evaluated the effectiveness of CNRL's disclosure controls and procedures as of the end of the period covered by this report and concluded that such disclosure controls and procedures are effective for the purpose for which they were designed as of the end of such period. During the fiscal year ended December 31, 2003, there were no changes in CNRL's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, CNRL's internal control over financial reporting. AUDIT COMMITTEE FINANCIAL EXPERT - -------------------------------- The Board of Directors of CNRL has named Ms. C.M. Best as an "audit committee financial expert" serving on its Audit Committee. Ms. C.M. Best is, as are all members of the Audit Committee of the Board of Directors of CNRL, "independent" as such term is defined in the New York Stock Exchange Listed Company Manual. AUDIT COMMITTEE - --------------- CNRL has a separately designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The members of the Audit Committee are Messrs. G. D. Giffin, J.S. Palmer, J.T. Grenon and Ms. C.M. Best. Mr. Giffin chairs the Audit Committee. PRINCIPAL ACCOUNTANT FEES AND SERVICES - -------------------------------------- PricewaterhouseCoopers LLP ("PWC") has been the auditors of CNRL since CNRL's inception. The aggregate amounts billed by PWC for each of the last two fiscal years for audit fees, audit-related fees, tax fees and all other fees, including expenses, are set forth below. AUDIT FEES: The aggregate fees billed for each of the last two fiscal years of CNRL ending December 31, 2003 and December 31, 2002, for professional services rendered by PWC for the audit of its annual financial statements or services that are normally provided by PWC in connection with statutory and regulatory filings or engagements for those fiscal years are $886,000 and $848,631, respectively. AUDIT-RELATED FEES: The aggregate fees billed for each of the last two fiscal years of CNRL, ending December 31, 2003 and December 31, 2002, for audit-related services by PWC consisting of regulatory changes consultation provided in 2003, and a review of financial statements of Rio Alto Exploration Inc. for the period prior to acquisition by CNRL and an external intrusion/vulnerability test of CNRL computer and information systems provided in 2002 were $12,500 and $28,000 respectively. CNRL's Audit Committee approved all of the noted services. TAX FEES: The aggregate fees billed for each of the last two fiscal years of CNRL, ending December 31, 2003 and December 31, 2002, for professional services rendered by PWC for tax-related services consisting of payroll tax filing consultation provided in 2003 and consultation on tax matters for foreign subsidiaries, transfer pricing study and other professional services related to tax matters provided in 2002 were $11,000 and $69,565, respectively. CNRL's Audit Committee approved all of the noted services. ALL OTHER FEES: The aggregate fees billed for each of the last two fiscal years of CNRL ending December 31, 2003 and December 31, 2002, for other services, consisting of debt covenant calculations, payroll consultation and training provided in 2003 and training, and consultation services provided in 2002, were $10,000 and $20,548, respectively. Additional fees of $851,911 were paid during 2002 to a company, wholly owned by PricewaterhouseCoopers LLP, for license and maintenance fees of the financial management and information system used by CNRL. During 2002 PricewaterhouseCoopers LLP sold the financial management and information system company, to a third party unrelated to PricewaterhouseCoopers LLP, and PricewaterhouseCoopers LLP no longer provides these services to CNRL. CNRL's Audit Committee approved all of the noted services. AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES: The Audit Committee's duties and responsibilities include the review and approval of fees to be paid to the independent auditors, scope and timing of the audit and other related services rendered by the independent auditors. The Audit Committee also reviews and approves the independent auditor's annual audit plan, including scope, staffing, locations and reliance upon management and internal audit department prior to the commencement of the audit and reviews and approves proposed non-audit services to be provided by the independent auditors except those non-audit services prohibited by legislation. OFF-BALANCE SHEET ARRANGEMENTS - ------------------------------ See page 51 of CNRL's Management's Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2003, filed herewith, under the caption "Off balance sheet arrangements and financial instruments." CONTRACTUAL OBLIGATIONS - ----------------------- CNRL has various commitments primarily related to debt, operating leases and demand charges on firm transportation agreements. The following table summarizes CNRL's commitments as at December 31, 2003.
- --------------------------------------------------------------------------------------------------------- ($ MILLIONS) TOTAL 2004 2005 2006 2007 2008 THEREAFTER - --------------------------------------------------------------------------------------------------------- Natural gas transportation 866 180 169 143 103 77 194 - --------------------------------------------------------------------------------------------------------- Crude oil transportation and 236 15 13 13 15 13 167 pipeline - --------------------------------------------------------------------------------------------------------- Offshore equipment operating 890 169 129 75 75 75 367 lease - --------------------------------------------------------------------------------------------------------- Electricity 82 28 27 27 -- -- -- - --------------------------------------------------------------------------------------------------------- Office lease 142 20 20 19 17 16 50 - --------------------------------------------------------------------------------------------------------- Processing 13 6 5 2 -- -- -- - --------------------------------------------------------------------------------------------------------- Preferred securities 103 -- -- -- -- -- 103 - --------------------------------------------------------------------------------------------------------- Long-term debt 2,561 184 194 -- 165 40 1,978 - --------------------------------------------------------------------------------------------------------- TOTAL 4,893 602 557 279 375 221 2,859 - ------------------------------------=====================================================================
CODE OF ETHICS - -------------- CNRL has had a long-standing Code of Integrity, Business Ethics and Conduct, which includes such topics as employment standards, conflict of interest, the treatment of confidential information and trading in CNRL's shares, to ensure that CNRL's business is conducted in a consistently legal and ethical manner. Each director and all employees including each member of senior management and more specifically the principal executive officers, the principal financial officer and the principal accounting officer are required to abide by CNRL's Code of Integrity, Business Ethics and Conduct. The Nominating and Corporate Governance Committee periodically reviews CNRL's Code of Integrity, Business Ethics and Conduct to ensure it addresses appropriate topics and complies with regulatory requirements and recommends any appropriate changes to the Board for approval. Any waivers of or amendments to CNRL's Code of Integrity, Business Ethics and Conduct must be approved by the Board of Directors and will be appropriately disclosed on CNRL's website at www.cnrl.com. No waivers to CNRL's Code of Integrity, Business Ethics and Conduct in whole or in part have been asked for or granted to any Director, senior officer or employee as of the date of this Annual Report. DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE - ---------------------------------------------------------------------- PRESIDING DIRECTOR AT MEETINGS OF NON-MANAGEMENT DIRECTORS - ---------------------------------------------------------- CNRL schedules regular executive sessions in which CNRL's "non-management directors" (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. G. D. Giffin serves as the presiding director (the "Presiding Director") at such sessions. COMMUNICATION WITH NON-MANAGEMENT DIRECTORS - ------------------------------------------- Shareholders may send communications to CNRL's non-management directors by writing to the Presiding Director, c/o Bruce E. McGrath, Corporate Secretary, Canadian Natural Resources Limited, 2500, 855 - 2nd Street S.W., Calgary, Alberta, T2P 4J8. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate. CORPORATE GOVERNANCE GUIDELINES - ------------------------------- In accordance with Section 303A.09 of the NYSE Listed Company Manual, CNRL has adopted a set of corporate governance guidelines, which are available in print at no charge to any shareholder who requests them. Requests for copies of the corporate governance guidelines should be made by contacting: Bruce E. McGrath, Corporate Secretary, Canadian Natural Resources Limited, 2500-855 2nd Street, S.W., Calgary, Alberta, Canada T2P 4J8. BOARD COMMITTEE CHARTERS - ------------------------ The charters of CNRL's Audit Committee, Nominating and Corporate Governance Committee and Compensation Committee are available in print at no charge to any shareholder who requests them. Requests for copies of these documents should be made by contacting: Bruce E. McGrath, Corporate Secretary, Canadian Natural Resources Limited, 2500-855 2nd Street, S.W., Calgary, Alberta, Canada T2P 4J8. UNDERTAKING AND CONSENT TO SERVICE OF PROCESS UNDERTAKING CNRL undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities. CONSENT TO SERVICE OF PROCESS The Company has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises. Any change to the name or address of the agent for service of process of CNRL shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement. SIGNATURES Pursuant to the requirements of the Exchange Act, CNRL certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereto duly authorized. Dated this 23rd day of April, 2004. CANADIAN NATURAL RESOURCES LIMITED By: /s/ John G. Langille --------------------------------------- Name: John G. Langille Title: President Documents filed as part of this report: EXHIBIT INDEX EXHIBIT NO. DESCRIPTION - ----------- ----------- 1. Annual Information Form for the fiscal year ended December 31, 2003. 2. Consolidated Financial Statements for the fiscal years ended December 31, 2003 and 2002 including U.S. GAAP reconciliation note, together with the auditors' report thereon. 3. Management's Discussion and Analysis for the fiscal year ended December 31, 2003. 4. Supplementary Oil & Gas Information for the fiscal year ended December 31, 2003. 5. Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934. 6. Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934. 7. Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). 8. Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350). 9. Consent of PricewaterhouseCoopers LLP, independent chartered accountants. 10. Consent of Sproule Associates Limited, independent petroleum engineering consultants. EX-99 3 ex1-form40f_2003.txt EXHIBIT 1 EXHIBIT 1 --------- CANADIAN NATURAL RESOURCES LIMITED ANNUAL INFORMATION FORM APRIL 2, 2004 1 TABLE OF CONTENTS DEFINITIONS....................................................................2 SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................3 THE COMPANY....................................................................4 GENERAL DEVELOPMENT OF THE BUSINESS............................................5 REGULATORY MATTERS.............................................................6 COMPETITIVE MATTERS............................................................8 ENVIRONMENTAL MATTERS..........................................................8 DESCRIPTION OF THE BUSINESS....................................................9 A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES...........................10 DRILLING ACTIVITY....................................................11 PRODUCING OIL AND GAS WELLS..........................................12 PRESENT ACTIVITIES...................................................12 NORTHEAST BRITISH COLUMBIA...........................................12 NORTHWEST ALBERTA....................................................13 NORTH ALBERTA........................................................14 HORIZON OIL SANDS PROJECT............................................16 SOUTH ALBERTA........................................................17 SOUTHEAST SASKATCHEWAN...............................................18 UNITED KINGDOM NORTH SEA.............................................18 OFFSHORE WEST AFRICA.................................................19 COTE D'IVOIRE........................................................19 ANGOLA...............................................................20 B. CRUDE OIL AND NATURAL GAS RESERVES.......................................20 C. RECONCILIATION OF CHANGES IN NET RESERVES................................25 D. CRUDE OIL AND NATURAL GAS PRODUCTION.....................................26 E. HISTORICAL DRILLING ACTIVITY BY PRODUCT..................................29 F. CAPITAL EXPENDITURES.....................................................30 G. NON-RESERVE ACREAGE......................................................32 H. DEVELOPED ACREAGE........................................................32 SELECTED FINANCIAL INFORMATION................................................33 MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................34 DIVIDEND HISTORY..............................................................34 DIRECTORS AND OFFICERS........................................................35 ADDITIONAL INFORMATION........................................................38 SCHEDULE "A"..................................................................40 SCHEDULE "B"..................................................................43 CURRENCY Unless otherwise indicated, all dollar figures stated in this Annual Information Form represent Canadian dollars. 2 DEFINITIONS The following are definitions of selected abbreviations used in this Annual Information Form: "ARTC" means Alberta Royalty Tax Credit. "BBL" or "BARREL" means 34.972 Imperial gallons or 42 U.S. gallons. "BCF" means one billion cubic feet. "BBLS/D" means barrels per day. "CANADIAN NATURAL RESOURCES LIMITED", "CANADIAN NATURAL", "CNRL" or "COMPANY" means Canadian Natural Resources Limited and includes, where applicable, reference to subsidiaries of and partnership interests held by Canadian Natural Resources Limited and its subsidiaries. "FPSO" means floating production, storage and off-take vessel. "GROSS ACRES" means the total number of acres in which the Company holds a working interest or the right to earn a working interest. "GROSS WELLS" means the total number of wells in which the Company has a working interest. "MBBLS" means one thousand barrels. "MCF" means one thousand cubic feet. "MCF/D" means one thousand cubic feet per day. "MMBBLS" means one million barrels. "MMBTU" means one million British thermal units. "MMCF" means one million cubic feet. "MMCF/D" means one million cubic feet per day. "NGLS" means natural gas liquids. "NET ACRES" refers to gross acres multiplied by the percentage working interest therein owned or to be owned by the Company. "NET WELLS" refers to gross wells multiplied by the percentage working interest therein owned or to be owned by the Company. "SAGD" means steam-assisted gravity drainage. "UNDEVELOPED LAND" or "NON-RESERVE ACREAGE" refers to lands on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas. "WORKING INTEREST" means the interest held by the Company in a crude oil or natural gas property, which interest normally bears its proportionate share of the costs of exploration, development, and operation as well as any royalties or other production burdens. "WTI" means West Texas Intermediate. Natural gas is converted to oil equivalent at the rate of six thousand cubic feet equals one barrel of oil equivalent. 3 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this document or incorporated herein by reference may constitute "forward-looking statements" within the meaning of the United States Private Litigation Reform Act of 1995. These forward-looking statements can generally be identified as such because of the context of the statements including words such as the Company "believes", "anticipates", "expects", "plans", "estimates", or words of a similar nature. The forward-looking statements are based on current expectations and are subject to known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others: the general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; the foreign currency exchange rates; the economic conditions in the countries and regions in which the Company conducts business; the political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the industry capacity; the ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition, availability and cost of seismic, drilling and other equipment; the ability of the Company to complete its capital programs; the ability of the Company to transport its products to market; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the operating hazards and other difficulties inherent in the exploration for and production and sale of oil and natural gas; the availability and cost of financing; the success of exploration and development activities; the timing and success of integrating the business and operations of acquired companies; the production levels; the uncertainty of reserve estimates; the actions by governmental authorities; the government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations); the site restoration costs; and other circumstances affecting revenues and expenses. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors, and management's course of action would depend upon its assessment of the future considering all information then available. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. The Company assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. 4 THE COMPANY Canadian Natural Resources Limited was incorporated under the laws of the Province of British Columbia on November 7, 1973 as AEX Minerals Corporation (N.P.L.) and on December 5, 1975 changed its name to Canadian Natural Resources Limited. CNRL was continued under the COMPANIES ACT OF ALBERTA on January 6, 1982 and was further continued under the BUSINESS CORPORATIONS ACT (Alberta) on November 6, 1985. The head, principal and registered office of the Company is located in Calgary, Alberta, Canada at 2500, 855 - 2nd Street S.W., T2P 4J8. CNRL formed a wholly owned subsidiary, CanNat Resources Inc. ("CanNat") in January 1995. Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding shares of Sceptre Resources Limited ("Sceptre") in September 1996 and in January 1997, Sceptre and CanNat amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name CanNat Resources Inc. Pursuant to an Offer to Purchase all of the outstanding shares, the Company completed the acquisition of Ranger Oil Limited, including its subsidiaries, ("Ranger") in July 2000. On October 1, 2000 Ranger and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited. Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding shares of Rio Alto Exploration Ltd. ("RAX") in July 2002. On January 1, 2003 RAX and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited. On January 1, 2004 CanNat and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited. The material operating subsidiaries of the Company, each of which is directly or indirectly wholly-owned, and their jurisdiction of incorporation are as follows: NAME OF COMPANY JURISDICTION OF INCORPORATION --------------- ----------------------------- CNR (ECHO) Resources Inc. Alberta CNR International (U. K.) Developments Limited England CNR International (U. K.) Limited England CNR International Cote d'Ivoire SARL Cote d'Ivoire Renata Resources Inc. Alberta CNRL as the managing partner and CNR (ECHO) Resources Inc. and Renata Resources Inc. are the partners of Canadian Natural Resources, a general partnership. Canadian Natural Resources as the managing partner and Renata Resources Inc. and CNRL are partners of Canadian Natural Resources Northern Alberta Partnership, a general partnership. The two partnerships hold the Canadian crude oil and natural gas properties of CNRL. CNRL also has a 15 per cent interest in Cold Lake Pipeline Ltd., which is the general partner of Cold Lake Pipeline Limited Partnership of which CNRL has a 14.7 per cent interest. The consolidated financial statements of CNRL include the accounts of the Company and all of its subsidiaries and partnerships. 5 GENERAL DEVELOPMENT OF THE BUSINESS CNRL's business is the acquisition of interests in crude oil and natural gas rights and the exploration, development, production, marketing and sale of crude oil and natural gas. The Company initiates, operates and maintains a large working interest in a majority of the prospects in which it participates. CNRL's objective is to increase cash flow and earnings through the development of its existing crude oil and natural gas properties and through the discovery and acquisition of new reserves. The Company's principal regions of crude oil and natural gas operations are in the Western Canadian Sedimentary Basin, the United Kingdom (the "UK") sector of the North Sea and Offshore West Africa. The Company has a full complement of management, technical and support staff to pursue these objectives. As at December 31, 2003 the Company had 1671 full time employees in North America and 204 full time employees in its international operations. In 2001, the Company completed 121 transactions in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate expenditure of $582.2 million. These properties are located in the Company's principal operating regions and are comprised of producing and non-producing leases together with related facilities. In addition, the Company disposed of non-operated properties not located in the Company's core regions for proceeds of $63.0 million, including a large portion of the properties acquired with Ranger in the United States Gulf Coast. On July 24, 2001, the Company issued US $400.0 million of 10 year 6.70 per cent unsecured notes maturing July 15, 2011 pursuant to a prospectus supplement dated July 19, 2001 to the short form shelf prospectus dated July 6, 2001. Pursuant to a prospectus supplement dated January 15, 2002 to the short form shelf prospectus dated July 6, 2001, the Company issued on January 23, 2002, US $400.0 million of 30 year 7.20 per cent unsecured notes maturing January 15, 2032. In July 2002, pursuant to the terms of a Plan of Arrangement, the Company acquired 100 per cent of RAX. The total purchase price was $2,393.2 million, comprised of $850.0 million in cash, $522.4 million attributable to the issue of 10,008,218 common shares of the Company, and the assumption of $936.3 million of debt and $84.5 million of working capital deficiency. The acquisition provided the Company with a new core region for natural gas exploration and exploitation activities in Northwest Alberta. The RAX properties include approximately 2.9 million net acres of undeveloped lands and provide additional opportunities for the Company to increase its production and reserves of natural gas and natural gas liquids. The acquisition added additional production, which averaged 376 million cubic feet per day of natural gas and 11 thousand barrels per day of crude oil and natural gas liquids during the second half of 2002 and 2-D and 3-D seismic of 57,820 kilometres and 14,565 square kilometres respectively. Future exploration and development projects will take advantage of the large undeveloped land base, high quality seismic database information and excess capacity within existing facilities. The acquisition solidified the Company as the second largest producer of natural gas in Canada and the second largest undeveloped landholder in western Canada. During 2002, the Company completed 128 transactions in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate expenditure of $516.3 million. These properties are located in the Company's principal operating regions and are comprised of producing and non-producing leases together with related facilities. 6 In addition, the Company disposed of non-operated properties not located in the Company's core regions for proceeds of $76.1 million. On September 16, 2002, the Company issued US $350.0 million of 10 year 5.45 per cent unsecured notes maturing October 1, 2012 and US $350.0 million of 31 year 6.45 per cent unsecured notes maturing June 30, 2033 pursuant to a prospectus supplement dated September 9, 2002 to a short form shelf prospectus dated August 16, 2002. During 2003, the Company completed 111 transactions in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate expenditure of $355.3 million. These properties are located in the Company's principal operating regions and are comprised of producing and non-producing leases together with related facilities. In addition, the Company disposed of non-operated properties not located in the Company's core regions for proceeds of $19.3 million. On February 18, 2004 the Company acquired certain resource properties located in East Central Alberta and Saskatchewan (collectively known as the Petrovera Partnership) for aggregate consideration of $701 million. In a separate transaction, the Company sold specific resource properties in the Petrovera Partnership, representing approximately one third of the total acquisition, to another independent producer for proceeds of $234 million, resulting in a net cost of $467 million for the retained properties. The net current production from the working interests retained by the Company was approximately 27.5 mbbl/d of heavy oil and 9 mmcf/d of natural gas together with volumes associated with royalty interests of 1.2 mbbl/d of heavy oil and 2 mmcf/d of natural gas. All of the retained properties are situated in the Company's core region of North Alberta. REGULATORY MATTERS The Company's business is subject to regulations generally established by government legislation and governmental agencies. The regulations are summarized in the following paragraphs. CANADA The petroleum and natural gas industry in Canada operates under various government legislation and regulations, which govern exploration, development, production, refining, marketing, prevention of waste and other activities. The Company's Canadian properties are located in Alberta, British Columbia, Saskatchewan, Manitoba and the Northwest Territories. Most of these properties are held under leases/licences obtained from the respective provincial or federal governments, which give the holder the right to explore for and produce crude oil and natural gas. The remainder of the properties are held under freehold (private ownership) lands. Conventional petroleum and natural gas leases issued by the provinces of Alberta, Saskatchewan and Manitoba have a primary term from two to five years, and British Columbia leases/licences presently have a term of up to ten years. Those portions of the leases that are producing or are capable of producing at the end of the primary term will "continue" for the productive life of the lease. The exploration licences in the Northwest Territories are administered by the Federal Government and only grant the right to explore. They have initial terms of four to five years. 7 A Commercial Discovery Licence must be obtained in order to produce crude oil and natural gas, which requires the approval of a satisfactory development plan. An oil sands permit and oil sands primary lease is issued for five and fifteen years respectively. If the minimum level of evaluation of an oil sands permit is attained, a primary oil sands lease will be issued out of the permit. A primary oil sands lease is continued based on the minimum level of evaluation attained on such lease. Continued primary oil sands leases that are designated as "producing" will continue for their productive lives while those designated as "non-producing" can be continued by payment of escalating rentals. The provincial governments regulate the production of crude oil and natural gas as well as the removal of natural gas and natural gas liquids from each province. Government royalties are payable on crude oil and natural gas production from leases owned by the province. The royalties are determined by regulation and are generally calculated as a percentage of production varied by a number of different factors including selling prices, production levels, recovery methods, transportation and processing costs, location and date of discovery. The Company is subject to federal and provincial income taxes in Canada at a combined rate of approximately 41 per cent after allowable deductions. UNITED KINGDOM Under existing law, the UK Government has broad authority to regulate the petroleum industry, including the power to regulate exploration, development, conservation and rates of production. Production from offshore fields as defined by applicable legislation, whose development was approved prior to April 1, 1982, were subject to Royalty of 12.5 per cent on or after deduction of certain allowances. Fields receiving development approval after April 1, 1982 were not subject to Royalty. On November 27, 2002, the UK Government announced the elimination of Royalty effective January 1, 2003. Crude oil and natural gas fields granted development approval before March 16, 1993 are subject to UK Petroleum Revenue Tax ("PRT") of 50 per cent charged on crude oil and natural gas profits. Crude oil and natural gas fields granted development approval on or after March 16, 1993 are exempted from PRT. Profits for PRT purposes are calculated on a field-by-field basis by deducting field operating costs and field development costs from production and third party tariff revenue. In addition, certain statutory allowances are available, which may reduce the PRT payable. The Company is subject to UK Corporation Tax ("CT") on its UK profits as adjusted for CT purposes. PRT paid is a deductible for CT purposes. The current CT rate, which became effective April 1, 1999, is 30 per cent. On April 17, 2002, the UK Government, in its 2002 budget speech by the UK Chancellor of the Exchequer, announced changes to taxation policies on UK North Sea crude oil and natural gas production. A supplementary CT charge of 10 per cent, charged on the same profits as calculated for `normal' CT but excluding any deduction for financing costs, was added to the current 30 per cent CT charge. Also the deduction for expenditures on capital items was changed from 25 per cent per annum to 100 per cent in the year incurred. OFFSHORE WEST AFRICA Terms of licences, including royalties and taxes payable on production or profit sharing arrangements, vary by country and in some countries by concession within each country. For instance, production from the Kiame field, on Block 4 in Angola, was subject to a 6 per cent 8 royalty on gross income and 50 per cent Petroleum Income Tax, which equates to 7 per cent calculated on the Company's gross income. Development of the Espoir field on CI-26, Cote d'Ivoire, is under the terms of a production sharing arrangement that provides that tax or royalty payments to the Government are deemed to be met from the Government's share of profit oil (See "Principal Crude Oil and Natural Gas Properties - Offshore West Africa"). Any changes in government policies or operating environment in the countries where the Company conducts business could have a significant impact on the Company's business ventures in such jurisdictions. Risks of foreign operations include, but are not necessarily limited to, changes of laws affecting foreign ownership, government participation, taxation, royalties, duties, rates of exchange, inflation, exchange control, repatriation of earnings and domestic or international unrest. The effect of changes in any of these factors cannot be accurately predicted. COMPETITIVE MATTERS The crude oil and natural gas industry, domestically and in the international arena, is highly competitive by nature. The Company must compete with integrated oil and natural gas companies and independent producers and marketers of crude oil and natural gas products in all aspects of the Company's business. This competition extends to exploration, property and asset acquisition and the selling of the Company's crude oil and natural gas products. The financial strength of some of the Company's competitors may be greater than that of the Company. ENVIRONMENTAL MATTERS The Company carries out its activities in compliance with all relevant regional, national and international regulations and best industry practice. Environmental specialists in the UK and Canada review the operations of the Company's world-wide interests and report on a regular basis to the senior management of the Company, which in turn reports on environmental matters directly to the Health, Safety and Environmental Committee of the Board of Directors. The Company regularly meets with, and submits to inspections by the various governments in the regions where the Company operates. At present, the Company believes that it meets all existing environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet current environmental protection requirements. Since these requirements apply to all operators in the crude oil and natural gas industry, it is not anticipated that the Company's competitive position within the industry will be adversely affected. The Company has internal procedures designed to ensure that the environmental aspects of new acquisitions and developments are taken into account prior to proceeding. The Company's environmental plan and operating guidelines focus on minimizing the environmental impact of field operations while meeting regulatory requirements and corporate standards. The Company's proactive program includes: an annual environmental compliance audit and inspection program of our operating facilities; an aggressive suspended well inspection program to support future development or eventual abandonment; appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; an effective surface reclamation program; progressive due diligence related to groundwater monitoring; prevention of and reclamation of spill sites, greenhouse gas reduction, and flaring and venting reduction. Canadian Natural participates in Canada's Climate Change Voluntary Challenge & Registry Inc. The Company has participated in the Canadian Association of Petroleum Producers (CAPP) Stewardship Program since 2000 and is currently a Gold Level Reporter. Canadian Natural 9 continues to invest in proven and new technologies and in improved operating strategies that will help us achieve our overall goal of a net reduction of greenhouse gas emissions per unit of production. The costs incurred by the Company for compliance with environmental matters and site restoration costs amount to less than 3 per cent of the total exploration and development expenditures incurred by the Company in each of the years ended December 31, 2003, 2002, and 2001. DESCRIPTION OF THE BUSINESS CNRL is a Canadian based senior independent energy company engaged in the acquisition, exploration, development, production, marketing and sale of crude oil, natural gas liquids and natural gas. The Company's principal core regions of operations are western Canada, the United Kingdom sector of the North Sea and Offshore West Africa. The Company focuses on exploiting its core properties and actively maintaining cost controls. Whenever possible CNRL takes on significant ownership levels, operates the properties and attempts to dominate the local land position and operating infrastructure. The Company has grown through a combination of internal growth and strategic acquisitions. Acquisitions are made with a view to either entering new core regions or increasing dominance in existing core regions. The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces: namely natural gas, NGLs, light oil, Pelican Lake oil, primary heavy oil and thermal heavy oil. The Company's operations are centred on balanced product offerings, which together provide complementary infrastructure and balance throughout the business cycle. Natural gas is the largest single commodity sold, accounting for 47 per cent of 2003 production. Virtually all of the Company's natural gas and natural gas liquids production is located in the Canadian provinces of Alberta and British Columbia and is marketed in Canada and the United States. Light oil and NGLs, representing 25 per cent of 2003 production, is located principally in the Company's North Sea and Offshore West Africa properties, with additional production in the Provinces of Saskatchewan, British Columbia and Alberta. Primary and thermal heavy oil operations in the Provinces of Alberta and Saskatchewan account for 23 per cent of 2003 production. Other heavy oil, which accounts for 5 per cent of 2003 production, is produced from the Pelican Lake area in north Alberta. This production, which has medium oil netback characteristics, is developed through a staged horizontal drilling program. Midstream assets, comprised of three crude oil pipelines and an electricity co-generation facility, provide cost effective infrastructure supporting the heavy and medium oil operations. CNRL expects its ownership of oil sands leases near Ft. McMurray, Alberta to provide a basis for long-term synthetic oil production growth. As a result of the Company's core undeveloped land base of 11.3 million net acres in western Canada, its international concessions and the Alberta oil sands leases, the Company believes it has sufficient project portfolios in each of the product offerings to provide growth for the next several years. 10 A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES Set forth below is a summary of the principal crude oil and natural gas properties as at December 31, 2003. The information is proportionate to the working interests and royalty interests owned by the Company.
2003 AVERAGE YEAR ENDED DAILY DECEMBER 31, INFRASTRUCTURE PRODUCTION RATES 2003 AS AT DECEMBER 31, 2003 ------------------ ----------------- ------------------------------- BATTERIES/ COMPPRESSORS & OIL & NATURAL UNDEVELOPED PIPELINE PLANTS/ NGLs GAS ACREAGE (thousand PLATFORMS REGION Mbbls MMcf (thousands) miles) /FPSO NORTH AMERICA Northeast B. C. 6.7 372.3 1,566 2.3 8/ 74/ --/ -- Northwest Alberta 11.1 261.3 1,681 2.2 8/ 29/ --/ -- North Alberta 136.7 462.4 5,627 6.7 23/ 97/ --/ -- Horizon Oil Sands -- -- 117 -- --/ --/ --/ -- South Alberta 10.9 141.9 673 3.3 34/ 61/ --/ -- SE Saskatchewan 9.2 3.4 147 -- 35/ --/ --/ -- Non - core regions 0.3 3.4 1,604 -- --/ --/ --/ -- INTERNATIONAL North Sea 56.9 45.6 1,920 0.1 --/ --/ 4/ 2 Offshore West Africa Angola -- -- 610 -- --/ --/ --/ -- Cote d'Ivoire 10.6 8.4 333 -- --/ --/ --/ 1 South Africa -- -- 5,550 -- --/ --/ --/ -- - ---------------------------------------------------------------------------------------------- TOTAL 242.4 1,298.7 19,828 14.6 108/ 261/ 4/ 3 - ----------------------------------------------------------------------------------------------
11 DRILLING ACTIVITY Set forth below is a summary of the drilling activity, excluding stratigraphic test and service wells, of the Company for each of the last two fiscal years up to December 31, 2003 by geographic region:
2003 - ------------------------------------------------------------------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL - ------------------------------------------------------------------------------------------------------------------------- CANADA 15.5 13.3 28.8 67.8 9.1 76.9 Northeast B. C. 31.7 11.8 43.5 69.9 7.9 77.8 Northwest Alberta 57.5 26.6 84.1 531.6 37.9 569.5 North Alberta 33.0 4.0 37.0 387.9 5.0 392.9 South Alberta -- -- -- 26.9 -- 26.9 Southeast Saskatchewan -- -- -- 0.4 -- 0.4 Non - core regions NORTH SEA -- 1.0 1.0 11.1 0.8 11.9 OFFSHORE WEST AFRICA Cote d'Ivoire 0.7 -- 0.7 0.7 -- 0.7 Angola -- 0.6 0.6 -- -- -- - ------------------------------------------------------------------------------------------------------------------------- TOTAL 138.4 57.3 195.7 1,096.3 60.7 1,157.0 - ------------------------------------------------------------------------------------------------------------------------- 2002 - ------------------------------------------------------------------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL - ------------------------------------------------------------------------------------------------------------------------- CANADA 16.8 4.4 21.2 25.4 -- 25.4 Northeast B. C. 3.9 3.0 6.9 6.1 -- 6.1 Northwest Alberta 31.5 6.0 37.5 278.1 8.6 286.7 North Alberta 12.0 -- 12.0 40.6 2.5 43.1 South Alberta -- -- -- 4.3 1.0 5.3 Southeast Saskatchewan NORTH SEA 0.4 -- 0.4 4.5 -- 4.5 OFFSHORE WEST AFRICA Cote D'Ivoire 0.6 0.9 1.5 1.8 0.6 2.4 - ------------------------------------------------------------------------------------------------------------------------- TOTAL 65.2 14.3 79.5 360.8 12.7 373.5 - ------------------------------------------------------------------------------------------------------------------------- 2001 - ------------------------------------------------------------------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL - ------------------------------------------------------------------------------------------------------------------------- CANADA 13.1 4.5 17.6 63.5 5.0 68.5 Northeast B. C. 3.0 1.0 4.0 2.0 -- 2.0 Northwest Alberta 60.7 8.1 68.8 231.3 12.7 244.0 North Alberta 1.4 -- 1.4 324.9 -- 324.9 South Alberta -- -- -- 4.0 -- 4.0 Southeast Saskatchewan -- -- -- -- -- -- Non - core areas UNITED STATES -- 0.8 0.8 0.1 -- 0.1 NORTH SEA -- 0.2 0.2 2.2 -- 2.2 OFFSHORE WEST AFRICA Cote D'Ivoire 0.6 -- 0.6 0.6 -- 0.6 Angola -- -- -- -- -- -- - ------------------------------------------------------------------------------------------------------------------------- TOTAL 78.8 14.6 93.4 628.6 17.7 646.3 - -------------------------------------------------------------------------------------------------------------------------
12 PRODUCING OIL & GAS WELLS Set forth below is a summary of the number of gross and net wells within the Company that were on production as of December 31, 2003:
- ----------------------------------------------------------------------------------------------------------------------- NATURAL GAS WELLS OIL WELLS TOTAL WELLS GROSS NET GROSS NET GROSS NET - ----------------------------------------------------------------------------------------------------------------------- CANADA 757 610.4 220 159.4 977 769.8 Northeast B. C. 665 539.4 150 108.2 815 647.6 Northwest Alberta 2,583 1,980.1 4,162 3,611.9 6,745 5,592.0 North Alberta 3,415 2,686.5 1,003 891.1 4,418 3,577.6 South Alberta 677 56.0 292 97.0 969 153.0 Southeast Saskatchewan -- -- 1,084 707.9 1,084 707.9 Non - core regions UNITED STATES 4 0.5 2 0.2 6 0.7 NORTH SEA 5 0.4 91 74.5 96 74.9 OFFSHORE WEST AFRICA Cote d'Ivoire -- -- 5 2.9 5 2.9 Angola -- -- -- -- -- -- - ----------------------------------------------------------------------------------------------------------------------- TOTAL 8,106 5,873.3 7,009 5,653.1 15,115 11,526.4 - -----------------------------------------------------------------------------------------------------------------------
PRESENT ACTIVITIES At December 31, 2003, the Corporation was in the process of drilling 47 gross wells (45.3 net wells). Injection of emulsion into the first waterflood injector of a demonstration project in the Pelican Lake field commenced to determine potential improvements in sweep efficiency and thus ultimate recovery. Waterflooding in the remaining injectors and monitoring the field's response to injection continued. NORTHEAST BRITISH COLUMBIA This region comprises lands from south of Fort St. John, British Columbia to the northern border of British Columbia. Similar geological attributes extend throughout the region, producing light oil, natural gas liquids and natural gas. The Company holds working interests ranging up to 100 per cent and averaging 78 per cent in 2,780,070 gross (2,158,094 net) acres of producing and undeveloped land in the region. Crude oil reserves are found primarily in the Halfway or lower Halfway formation, while natural gas and associated natural gas liquids are found in numerous zones at depths reaching approximately 2,000 vertical meters. In the southern portion of the region, the Company owns natural gas producing and undeveloped lands in which the productive zones are at deeper depths up to 3,500 meters. The exploration strategy focuses on comprehensive evaluation through two-dimensional seismic, three-dimensional seismic and targeting economic geological areas close to existing infrastructure. Applying under-balanced, multi-leg horizontal drilling has also proven highly effective in this region. Natural gas production from the region averaged 372.3 million cubic feet per day for 2003 compared to the average of 450.6 million cubic feet per day produced for 2002. Crude oil and natural gas liquids production decreased to 6.7 thousand barrels per day in 2003 from an average of 7.4 thousand barrels per day in 2002. 13 This region also contains the Ladyfern Slave Point natural gas pool, which was placed on production in mid-2001. Prior to the first quarter of 2002, production from the pool had been restricted due to insufficient processing facilities and pipelines, with production exiting 2001 at approximately 150 million cubic feet per day. In the first quarter of 2002, additional facilities were constructed, which enabled the Company to increase production to approximately 210 million cubic feet per day in June 2002. In late August 2002, water encroachment resulted in the commencement of anticipated significant declines from the pool. At the end of 2002, production was at 100 million cubic feet per day, falling to approximately 31 million cubic feet per day in December 2003. Through the acquisition of Ranger in 2000, the Company acquired an interest and operatorship in extensive acreage adjacent to the northern border of this region. A further acquisition in the fourth quarter of 2001 resulted in the Company obtaining 100 per cent ownership in its producing natural gas assets and undeveloped land in the Helmet area of the region. Further development of this acreage will be enhanced through the facilities and infrastructure owned by the Company in the region. Having identified optimal drilling strategies in the region, the Company implemented a multi-well annual drilling program, which resulted in 35 wells being drilled in 2003. During 2003, the Company developed a new exploration and development program that targets natural gas found in the shallow Notikewin formation in the Fort St. John area. Wells drilled into this formation produce at rates of 500 to 700 thousand cubic feet per day. In combination with the Company's extensive land base and the recently reduced royalty rates in British Columbia, this shallow gas drilling program will add to the Company's opportunities in this region. During 2003 the Company drilled 5.1 (2002-2.1) net oil wells, 78.2 (2002-40.1) net natural gas wells, 0.0 (2002-1.0) net service wells and 22.4 (2002-4.4) net dry wells on its lands in this region for a total of 105.7 (2002-47.6) net wells. The Company held an average 93 per cent working interest in these wells. NORTHWEST ALBERTA The Company holds working interests ranging up to 100 per cent and averaging 81 per cent in 2,542,232 gross (2,066,138 net) acres of producing and undeveloped land in the region located along the border of British Columbia and Alberta west and north of Edmonton. The majority of the Company's holdings in the region were obtained through the Plan of Arrangement in 2002, which facilitated the acquisition of RAX. This region contains exceptional exploration and exploitation opportunities as well as substantial available capacity within an extensively owned and operated infrastructure. In this region, Canadian Natural produces liquids rich natural gas from multiple, often technically complex horizons, with formation depths ranging from 1,000 to 4,500 metres. The northern portion of this core region provides extensive multi-zone Cretaceous opportunities similar to the geology of the Company's North Alberta core region. The southern portion provides a significant opportunity in the regionally extensive Cretaceous Cardium zone. The Cardium is a complex, tight natural gas reservoir where high productivity may be achieved due to greater matrix porosity or natural fracturing. In this southern portion, Canadian Natural pursued a modest well drilling program in the first half of 2003 so that detailed geological, geophysical and engineering work could be completed and interpreted. A more extensive drilling program was commenced in the last quarter of 2003. Natural gas production from the region averaged 261.3 million cubic feet per day for 2003 compared to an average of 171.2 million cubic feet per day for 2002. Crude oil and natural gas liquids production increased to 11.1 thousand barrels per day in 2003 from 6.6 thousand barrels per day in 14 2002. During 2003 the Company drilled 3.7 (2002-2.1) net oil wells, 97.9 (2002-7.5) net natural gas wells, and 19.7 (2002-3.0) net dry wells on its lands in this region for a total of 121.3 (2002-12.6) net wells. The Company held an average 85 per cent working interest in these wells. The Company owns and operates significant production facilities in this region, many of which have excess capacity, providing for cost effective future expansion of operations. All of the facilities are in close proximity to sales facilities. NORTH ALBERTA The Company holds working interests ranging up to 100 per cent and averaging 82 per cent in 9,602,862 gross (7,896,464 net) acres of producing and undeveloped land in the region located north of Edmonton to Fort McMurray and east to the border with Saskatchewan and extending into western Saskatchewan. Over most of the region both sweet and sour natural gas reserves are produced from numerous productive horizons at depths up to approximately 1,500 meters. In the southwest portion of the region, natural gas liquids and light oil are also encountered at slightly deeper depths. The region continues to be one of the Company's largest natural gas producing regions, with natural gas production from the region amounting to 462.4 million cubic feet per day in 2003 compared to 419.8 million cubic feet per day in 2002. Crude oil and natural gas liquids production from this region increased to 136.7 thousand barrels per day in 2003 from 135.9 thousand barrels per day in 2002. Production of natural gas was impacted by the shut-in effective September 1, 2004 of approximately 11 million cubic feet per day in the Athabasca Wabiskaw-McMurray oil sands area pursuant to the decision of the Alberta Energy and Utilities Board. In the area near Lloydminster, Alberta, reserves of heavy oil (averaging 12(Degree) - 14(degree) API) and natural gas are produced through conventional vertical, slant and horizontal well bores from a number of productive horizons up to 1,000 meters deep. The energy required to flow the heavy oil to the wellbore in this type of heavy oil reservoir comes from solution gas. The oil viscosity and the reservoir quality will determine the amount of crude oil produced from the reservoir, which will vary from 3 to 20 per cent. A key component to maintaining profitability in the production of heavy oil is to be a low cost producer. The Company continues to achieve low costs producing heavy oil by holding a dominant position that includes a significant land base and an extensive infrastructure of batteries and disposal facilities. The price received for heavy oil is discounted from the benchmark WTI price and during the last quarter of 2000, this differential widened to historically high levels. As a result, the Company took a proactive stance and consciously reduced the number of heavy oil wells drilled in 2001, reduced heavy oil production by 15 thousand barrels per day beginning December 2001 and changed the steaming pattern at its Primrose facility. Following the return of the heavy oil differential to more historical levels, the Company brought most of this production back online and expanded its 2002 and 2003 drilling programs. The Company continues to monitor and develop the heavy oil market and work on strategies to eliminate some of the uncertainty surrounding this commodity pricing. Ranger owned significant land and production in this region, with much of its land being contiguous to the Company's holdings. With the operations combined in 2000, future development of the total lands in the region became more effective and provided opportunities for cost savings. As part of the acquisition of Ranger, the Company also acquired a 50 per cent interest in the ECHO Pipeline system, a crude oil transportation pipeline; and, in 2001 the Company acquired the remaining 50 per cent. The pipeline was extended north to the Company operated Beartrap field during 2001, enhancing further development of the Company's extensive holdings in the area. This pipeline was 15 capable of transporting 57 thousand barrels per day of hot unblended crude oil to sales facilities at Hardisty, Alberta and in 2003 its capacity was expanded to handle up to 72 thousand barrels per day. The ECHO Pipeline system is a high temperature, insulated pipeline that eliminates the requirement for field condensate blending. The pipeline enables the Company to transport its own production volumes at a reduced operating cost as well as earn third party transportation revenue. The ECHO Pipeline system, together with other midstream assets in which the Company has partial interests, permits the Company to transport in excess of 80 per cent of its heavy oil to the international mainline liquids pipelines. This transportation control enhances the Company's ability to control the full spectrum of costs associated with the development and marketing of its heavy oil. Production from the 100% owned Primrose and Wolf Lake fields located near Bonnyville, Alberta involves processes that utilize steam to increase the recovery of the oil. The two processes employed by the Company are cyclic steam stimulation and SAGD. Both recovery processes inject steam to heat the heavy oil deposits, reducing the oil viscosity and therefore improving its flow characteristics. There is also an infrastructure of gathering systems, a processing plant with a capacity of 60 thousand barrels per day and a 50 per cent interest in a co-generation facility capable of producing 84 megawatts of electricity for the Company's use and sale into the Alberta power grid at pool prices. In 2000, the Company successfully converted and tested two existing pads of wells from low-pressure steaming to high-pressure steaming. This conversion increased average production at the 20 existing wells from 100 to 190 barrels of crude oil per day per well. An additional 24 wells were drilled using the high-pressure steam process with initial production averaging 600 barrels of crude oil per day per well. These results have confirmed the benefits of converting the Primrose field to high-pressure steaming. In 2001, the Company received regulatory approval to convert an additional six low-pressure cyclic pads to high-pressure cyclic pads, and in 2002 received approval to take high-pressure steam methodologies throughout the field. Canadian Natural drilled 48 high-pressure wells in 2003, which will increase field production commencing in 2004. Additional development of the leases will be undertaken in phases over the next several years. A successful SAGD heavy oil project in which the Company holds a 50 per cent interest is also in operation in the Saskatchewan portion of this region. Included in the northern part of this region, approximately 200 miles north of Edmonton, are the Company's 100 per cent owned holdings at Pelican Lake. These lands contain reserves of 14(Degree)-17(Degree) API heavy oil. Operating costs are low due to no sand production or disposal requirements, the gathering and pipeline facilities in place and negligible water production and disposal. The Company has the major ownership position in the necessary infrastructure including roads, drilling pads, gathering and sales pipelines, batteries, gas plants and compressors to ensure future economic development of the large crude oil pool located on the lands. In the first quarter of 2001, the Company added to its holdings in this area through the acquisition of additional producing lands from another industry participant. Following this acquisition, the Company holds and controls in excess of 80 per cent of the known crude oil pool in this area. This field contains approximately three billion barrels of original oil-in-place but is only expected to achieve a 5 per cent recovery factor using existing primary technologies on the Company's developed leases. Hence, in 2002 the Company embarked upon an Enhanced Oil Recovery ("EOR") scheme using an emulsion flood to increase the ultimate recoveries from the field. The experimental Pelican Lake emulsion flood showed that the recovery mechanism was very efficient; however, response time is slow. In view of the slow response time, the Company has reverted to a waterflood scheme for this field, which will increase the overall recovery factor but not to the extent reached under an emulsion scheme. This waterflood will be implemented in phases with approximately 20 per cent of the field scheduled to be under waterflood by the end of 2004. The implementation plan will result in the conversion of existing producing wells into water injectors and the drilling of additional producing 16 wells. The Company will also examine opportunities to use emulsion flooding in conjunction with waterflooding to obtain the highest recovery factor while maximizing value. During 2003 in this region, the Company drilled 405.7 (2002 - 246.0) net oil wells, 183.4 (2002 - 62.4) net natural gas wells, 58.5 (2002 - 148.5) net stratigraphic tests wells, 5.0 (2002 - 2.5) net services wells and 64.5 (2002 - 15.0) net dry wells that were abandoned for a total of 717.1 (2002 - 474.4) net wells. The Company's average working interest in these wells was in excess of 93 per cent. The Company operates and owns significant infrastructure in the region as shown above and has additional interests in plants and compressors in the region that are operated by other companies. HORIZON OIL SANDS PROJECT Canadian Natural owns a 100 percent working interest in 116,596 gross acres in the Athabasca Oil Sands area of Northern Alberta. The Horizon Oil Sands Project ("the Horizon Project") is located on these leases, about 80-km north of Fort McMurray. The project includes surface oil sands mining, bitumen extraction, bitumen upgrading to produce a 34-36o API synthetic light crude oil ("SCO"), and associated infrastructure. The project is designed as a phased development. Major site clearing and pre-construction preparation activities will commence upon completed regulatory approval and project sanction in 2004 and construction would continue through 2012. Phase 1 production is planned to begin in the fourth quarter of 2008 at 110 thousand barrels per day of SCO. Phase 2 would increase production to 155 thousand barrels per day of SCO in 2010. Phase 3 would further increase production to 232 thousand barrels per day of SCO in 2012. These projected rates of production represent nominal design capacity. Canadian Natural will seek to maximize resource recovery and overall production through ongoing optimization of operations. The phased approach provides the Company with improved cost and project controls in terms of labour and materials management and directionally mitigates the effects of growth on local infrastructure. Total expected capital costs of the phased development are $8.0 billion to $8.5 billion, of which approximately $5.0 billion would be required for Phase 1. These costs are consistent with final actual costs incurred by other recent oil sands mining projects. When the Horizon Project is fully commissioned, operating costs - including sustaining capital - are expected to be in the range of $9 to $11 per barrel. Drilling to date indicates an estimated 16 billion barrels of bitumen-in-place on the Company's Athabasca Oil Sands Leases. Over its forty-year life span the Horizon Project is expected to recover about six billion barrels of bitumen. Additional surface mining and in-situ potential exists on the portion of leases not comprising the Horizon Project. No reserves from these leases are included in the Company's current reserves of crude oil and natural gas liquids pending final regulatory and corporate approvals, subsequent capital expenditures and initiation of production. Canadian Natural filed an application for regulatory approval of the Horizon Project in June 2002. The application included a comprehensive environmental impact assessment and a social and economic assessment and was accompanied by public consultation. A federal-provincial regulatory Joint Review Panel (the "Panel") examined the project in a public hearing in September 2003. The Panel issued its decision report in January 2004, finding that the Horizon Project is in the public interest. Subsequent to the Panel decision, the Company has received approval for the Horizon Project from the Alberta Energy and Utilities Board and the Cabinets of both the Government of Canada and Alberta. Further approvals pursuant to specific government acts and regulations are expected mid-2004. 17 Due to uncertainties about the long term cost implications of the Government of Canada climate change policies, in late 2002 Canadian Natural reduced its estimate of 2003 capital expenditures for the Horizon Project from $300 million to $211 million. Throughout the first half of 2003, Canadian Natural, along with other major energy project proponents and the Canadian Association of Petroleum Producers actively sought greater clarity from the federal government about the long-term climate change policy framework. Of particular concern was the period beyond 2012 when policies will be derived from Canada's negotiations for a second Kyoto implementation phase. In mid 2003 the Government of Canada acknowledged the need for greater clarity and established eight principles that will guide the Government of Canada's longer-term climate change policies. These eight guiding principles addressed the key concerns of Canadian Natural with regard to equability, efficiency, flexibility and competitiveness issues for the post-2012 period. Canadian Natural is using a structured system called Front End Loading to ensure that project definition is adequate and complete before proceeding with implementation. This system is used successfully worldwide to mitigate risk on large capital projects in a variety of industries. The process is well documented at every step and is audited by an independent organization. In June 2002, the Company commenced the Design Basis Memorandum (DBM), which is the second of three front-end engineering phases. The DBM was completed for all project components in February 2004. In August 2003, the Company commenced work on the third front-end engineering phase, Engineering Design Specifications (EDS), on those components where the DBM was complete. The EDS will provide sufficient definition for lump sum bids on various project components, and a final detailed cost estimate that will provide the basis of project sanction by the Company's Board of Directors. Completion of this phase is expected in the last quarter of 2004. During 2003, the Company drilled 370 (2002 - 293) stratigraphic test wells to further delineate the ore body and confirm resource quality and quantity. SOUTH ALBERTA The Company holds interests ranging up to 100 per cent and averaging 81 per cent in 1,726,760 gross (1,390,732 net) acres of producing and undeveloped land in the region principally located south and east of Calgary. Reserves of natural gas, condensate and light and medium gravity crude oil are contained in numerous productive horizons at depths up to 2,300 meters. Unlike the Company's other three natural gas producing regions, which have areas with limited or winter access only, drilling can take place in this region throughout the year. With a higher sales price for natural gas, it is economic to drill shallow wells in closer proximity to each other, which may have smaller overall reserves and lower productivity per well but will achieve a high return on capital employed with low drilling costs and longer life reserves The Company maintains a large inventory of drillable locations on its land base in this region. This region is in the most mature portion of the Western Canadian Sedimentary Basin and requires continual operational cost control through efficient utilization of existing facilities, flexible infrastructure design and consolidation of interests where appropriate. The Company's share of production averaged 10.9 (2002 - 9.0) thousand barrels of crude oil and natural gas liquids per day and 141.9 (2002- 145.8) million cubic feet of natural gas per day in 2003. 18 During 2003, the Company drilled a total of 4.4 (2002 - 1.0) net oil wells, 416.5 (2002 - 51.6) net natural gas wells and 9.0 (2002 - 2.5) net dry wells in this region for a total of 429.9 (2002 - 55.1) net wells. The Company's average working interest in these wells is in excess of 97 per cent. The wells are predominantly in areas where the Company already has gathering and processing facilities. SOUTHEAST SASKATCHEWAN The Williston Basin is located in Southeastern Saskatchewan with lands extending into Manitoba and North Dakota. This region was owned by Sceptre and became a core region of the Company in mid 1996 with the acquisition of Sceptre. The Company holds interests ranging up to 100 per cent and averaging 81 per cent in 273,371 gross (219,124 net) acres of producing and undeveloped lands in the region. The region produces primarily light sour crude oil from as many as seven productive horizons found at depths up to 2,700 meters. During 2003, net production to the Company averaged 9.2 (2002 - 9.4) thousand barrels of crude oil and natural gas liquids and 3.4 (2002 - 3.2) million cubic feet of natural gas per day in 2003. The Company drilled 26.9 (2002 - 4.3) net oil wells and no (2002 - 1.0) net dry wells in this region in 2003 for a total of 26.9 (2002 - 5.3) net wells. The Company's average working interest in these wells is 84 per cent. UNITED KINGDOM NORTH SEA The Company's wholly owned subsidiary CNR International (U.K.) Limited, formerly Ranger Oil (U.K.) Limited, has operated in the North Sea for 30 years and has developed a significant database, extensive operating experience and an experienced staff. The Company owns interests ranging from 7 per cent up to 100 per cent in 910,183 gross (638,749 net) acres of producing and non-producing properties in the UK sector of the North Sea. In 2003, the Company produced from 9 crude oil fields. The northerly fields are centered around the Ninian Field where the Company has an 87.1 per cent working interest. The central processing facility is connected to other fields including the Columba and Lyell Fields where the Company operates with working interests of 91.6 per cent to 100 per cent. In 2002, the Company completed property acquisitions in the northern North Sea that increased ownership levels in the Ninian, Murchison, Lyell and Columba Terraces Fields. As part of the transaction the Company also acquired an interest in the Strathspey Field and 12 licenses covering 20 exploration blocks and part blocks surrounding the Ninian and Murchison platforms. Increased ownership in the Brent and Ninian pipelines and the Sullom voe Terminal was also acquired. In 2003 the Company further consolidated its ownership with the acquisition of additional working interests in the Ninian and Columba Fields, associated facilities and adjacent exploration acreage. Ownership and operatorship levels in the North Sea are now similar to those levels found throughout the Company's other worldwide operations. The Company also receives tariff revenue from other field owners for the transportation and processing of crude oil and natural gas through the processing facilities. Opportunities for further long-reach well development on adjacent fields are provided from the existing processing facilities. In the central portion of the North Sea, in 2003 the Company increased its equity in the Banff Field to 87.6 per cent and took over as operator. The Company also owns a 45.7 per cent operated working interest in the Kyle Field. During 2003, production to the Company from this region averaged 56.9 (2002 - 38.8) thousand barrels of crude oil per day and 45.6 (2002 - 27.1) million cubic feet of natural gas per day. The Company drilled 11.1 (2002 - 4.9) net oil wells, 4.8 (2002 - 1.2) net service wells and 1.8 (2002 - 0.0) net dry wells in 2003 in this region for a total of 17.7 (2002 - 6.1) net wells. The Company's average working interest in these wells is 84 per cent. 19 OFFSHORE WEST AFRICA With the purchase of Ranger in 2000, the Company acquired interests in areas of crude oil and natural gas exploration and development offshore Cote d'Ivoire and Angola, West Africa. The Company owns working interests ranging from 50 per cent to 100 per cent in 1,685,151 gross (952,006 net) acres in those countries. The Company also has a 100 per cent interest in 5,550,428 acres offshore South Africa where it is shooting and evaluating seismic. COTE D'IVOIRE The Company owns interests in three exploration licences offshore Cote d'Ivoire comprising 336,758 net acres. During 2001, the Company increased its interest in Block CI-26, which contains the Espoir crude oil and natural gas field, to a 59 per cent operating interest. The Espoir field is located in water depths ranging from 100 to 700 meters. During the 1980s, the Espoir field produced approximately 31 million barrels of crude oil by natural depletion prior to relinquishment by the previous licencees in 1988. The government of Cote d'Ivoire approved a development plan to recover the remaining reserves and the Company will continue its exploitation and development of the field. The development of East Espoir, which includes the drilling of both producing and water injection wells from a single wellhead tower was completed in 2003. Finalization of development plans for the West Espoir field will be completed in 2004. Oil from the East Espoir field is produced into an FPSO with associated natural gas delivered onshore through a subsea pipeline for local power generation. During December 2002 a satellite pool, Emien, was drilled, but encountered no hydrocarbons. The Company drilled a second, satellite pool, Acajou, during the first half of 2003. The Acajou well encountered a reservoir with good quality and hydrocarbons but not of sufficient size to warrant tie-back to the Espoir FPSO. Further evaluation will be undertaken to determine if the Acajou structure extends across additional lands. In the first quarter of 2001, the Company drilled and tested the Baobab exploration prospect, identified on Block CI-40, in which the Company has a 58 per cent interest, eight kilometres south of the Espoir facilities. The well encountered hydrocarbons at a rate of 6.7 thousand barrels of crude oil per day. A second test well in 2002 also produced hydrocarbons at a rate in excess of 10 thousand barrels of crude oil per day. The Company established a field development plan, which was approved by the Government of Cote d'Ivoire in December 2002. In 2003 the Company awarded four major contracts for the development of the Baobab Field. These contracts included the deep water drilling rig to drill 8 producing and 3 water injection wells, the FPSO, supplies for the subsea equipment and the supply of pipeline and risers, and installation of the subsea infrastructure. Development commenced in late 2003 with the drilling of the first water injection well. The development continues for first oil planned at initial gross production rates of 45 thousand barrels per day in 2005, increasing with full development to 60 thousand barrels per day. To date political unrest in Cote d'Ivoire has had no impact on the Company's operations. The Company has developed contingency plans to continue Cote d'Ivoire operations from another nearby country if the situation warrants such a move. During 2003, net daily production to the Company averaged 10.6 (2002 - 6.0) thousand barrels of crude oil and 8.4 (2002 - 1.3) million cubic feet of natural gas. In 2003, the Company drilled 1.3 (2002 - 2.4) net oil wells, 2.0 (2002 - 0.6) net service wells and 0.0 (2002 - 1.2) net dry wells for a total of 3.3 (2002 - 4.2) net wells. The Company's average working interest in these wells is 67 per cent. 20 ANGOLA During 2002, Canadian Natural was awarded operatorship and a 50 per cent working interest in exploration Block 16 situated offshore The People's Republic of Angola. Canadian Natural obtained 3-D seismic over the entire Block 16 before obtaining title and identified two targets, Omba in the north and Zenza in the west central portion of the Block. The Company has a two well commitment over a four year time frame expiring August 31, 2006. The first well, Zenza-1, was drilled during the fourth quarter of 2003 and was not considered commercial. The second exploratory well is expected to be drilled in the first quarter of 2005 following analysis of the Zenza results and further seismic reprocessing. The Company also owned 100 per cent of and operated the offshore Kiame Field. The field produced from June 1998 to April 2002 through a leased FPSO. The field reached its economic limit of production and production ceased in April 2002. The wells were abandoned and the associated seabed equipment safely recovered during 2003. The Company also had a 25 per cent non-operating interest in Block 19, on which a 3-D seismic survey was completed in 1999. After interpretation of the seismic and drilling of a 25 per cent interest well in 2002 on Block 19, the Company determined the block was not economic to develop and relinquished its license on the block. B. CRUDE OIL AND NATURAL GAS RESERVES The Company retains independent qualified petroleum engineering consultants Sproule Associates Limited ("Sproule") to evaluate 100% of the Company's proved and proved and probable crude oil and natural gas reserves and prepare evaluation reports on the Company's total reserves ("Evaluation Reports"). The Company has been granted an exemption from the recently adopted National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") which prescribes the standards for the preparation and disclosure of reserves and reserves related information for companies listed on stock exchanges in Canada. This exemption allows the Company to substitute United States Securities and Exchange Commission ("SEC") requirements for certain disclosures required under NI 51-101. The primary difference between the two standards is the additional requirement under NI 51-101 to disclose both proved and proved plus probable reserves as well as related future net revenues using forecast prices and costs. The Company has disclosed proved reserves using constant prices and costs as mandated by the SEC and has elected to provide proved plus probable reserves and values under the same parameters as well as proved and proved plus probable reserves using forecast prices and costs as additional voluntary information. Another difference between the two standards lies in the definition of proved reserves. As discussed in the Canadian Oil and Gas Evaluation handbook ("COGEH"), the standards which NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. The Reserves Committee of the Board of Directors of the Company has met with Sproule and carried out the appropriate independent due diligence procedures with Sproule to review the qualifications of and procedures used by Sproule in determining the estimate of the Company's quantities and value of remaining petroleum and natural gas reserves. The following tables summarize the evaluations of reserves and estimated future net revenues at December 31, 2003. THE ESTIMATED FUTURE NET REVENUES CONTAINED IN THE FOLLOWING TABLES ARE NOT TO BE CONSTRUED AS A REPRESENTATION OF THE FAIR MARKET VALUE OF THE PROPERTIES TO WHICH THEY RELATE. THE ESTIMATED FUTURE NET REVENUES DERIVED FROM THE ASSETS ARE PREPARED PRIOR TO CONSIDERATION OF INCOME TAXES 21 AND EXISTING ASSET ABANDONMENT LIABILITIES. NO INDIRECT COSTS SUCH AS OVERHEAD, INTEREST AND ADMINISTRATIVE EXPENSES HAVE BEEN DEDUCTED FROM THE ESTIMATED FUTURE NET REVENUES. OTHER ASSUMPTIONS AND QUALIFICATIONS RELATING TO COSTS, PRICES FOR FUTURE PRODUCTION AND OTHER MATTERS ARE SUMMARIZED IN THE NOTES TO THE FOLLOWING TABLES. THERE IS NO ASSURANCE THAT THE PRICE AND COST ASSUMPTIONS CONTAINED IN EITHER THE CONSTANT OR FORECAST CASES WILL BE ATTAINED AND VARIANCES COULD BE SUBSTANTIAL. CRUDE OIL, NGL AND NATURAL GAS RESERVES (NET OF ROYALTIES)
CONSTANT PRICES AND COSTS ----------------------------------------------------------------------- NET NET CRUDE OIL & NGL RESERVE NATURAL GAS RESERVE VOLUMES (MMbbls) VOLUMES (Bcf) ----------------------------------- ---------------------------------- TOTAL TOTAL PROVED AND PROVED AND PROVED PROBABLE PROVED PROBABLE RESERVES RESERVES RESERVES RESERVES -------- -------- -------- -------- NORTH AMERICA Canada 588 857 2,425 2,917 United States -- -- 1 2 INTERNATIONAL United Kingdom 222 317 62 102 Cote d'Ivoire 85 133 64 72 -------------- ------------------- ------------- ------------------- TOTAL 895 1,307 2,552 3,093 ============== =================== ============= ===================
CRUDE OIL, NGL AND NATURAL GAS RESERVES
CONSTANT PRICES AND COSTS ------------------------------------------------------------------------- CRUDE OIL AND NATURAL GAS LIQUIDS (MMbbls) NATURAL GAS (Bcf) ------------------------------------ --------------------------------- GROSS NET GROSS NET ----- --- ----- --- Proved developed 568 509 2,725 2,198 Proved undeveloped 432 386 429 354 ---------------- ------------------ --------------- ---------------- Total proved reserves 1,000 895 3,154 2,552 Total proved and probable reserves 1,481 1,307 3,823 3,093 ================ ================== =============== ================
ESTIMATED FUTURE NET REVENUES
($Millions) CONSTANT PRICES AND COSTS --------------------------------------------------------------------- UNDISCOUNTED DISCOUNTED AT --------------------- -------------------------------------------- 10% 15% 20% --- --- --- Proved developed $21,079 $13,080 $11,222 $9,902 Proved undeveloped 6,370 3,037 2,273 1,752 --------------------- ------------- ------------- -------------- Total proved reserves 27,449 16,117 13,495 11,654 Total proved and probable reserves $36,981 $20,167 $16,460 $13,929 ===================== ============= ============= ==============
22 CRUDE OIL, NGL AND NATURAL GAS RESERVES
FORECAST PRICES AND COSTS --------------------------------------------------------------------- CRUDE OIL AND NATURAL NATURAL GAS (Bcf) GAS LIQUIDS (MMbbls) ----------------------------------- ----------------------------- GROSS NET GROSS NET ----- --- ----- --- Proved developed 563 511 2,706 2,184 Proved undeveloped 432 398 429 361 ----------------- ---------------- -------------- ------------- Total proved reserves 995 909 3,135 2,545 Total proved and probable reserves 1,480 1,332 3,797 3,079 ================= ================ ============== =============
ESTIMATED FUTURE NET REVENUES
($ Millions) FORECAST PRICES AND COSTS --------------------------------------------------------------------- UNDISCOUNTED DISCOUNTED AT --------------------- -------------------------------------------- 10% 15% 20% --- --- --- Proved developed $15,949 $ 9,819 $ 8,464 $ 7,511 Proved undeveloped 4,705 2,054 1,471 1,079 --------------------- ------------- ------------- -------------- Total proved reserves 20,654 11,873 9,935 8,590 Total proved and probable reserves $28,056 $14,893 $12,118 $10,247 ===================== ============= ============= ==============
NOTES 1. "Gross" reserves means the total working interest share of remaining recoverable reserves owned by the Company before deduction of royalties payable to others. 2. "Net" reserves mean the Company's gross reserves less all royalties payable to others plus royalties receivable from others. 3. "Proved developed" reserves were evaluated using SEC standards and can be expected to be recovered through existing wells with existing equipment and operating methods. SEC standards require that these be evaluated using year-end constant prices and costs and be disclosed net of royalties. The Company has also provided these reserves and their associated values using forecast prices and costs as well as before royalties as additional voluntary information. 4. "Proved undeveloped" reserves were evaluated using SEC standards and are expected to be recovered from new wells on undrilled acreage, or from existing wells where relatively major expenditures are required for the completion of these wells or for the installation of processing and gathering facilities prior to the production of these reserves. Reserves on undrilled acreage are limited to those drilling units offsetting productive wells that are reasonably certain of production when drilled. SEC standards require that these be evaluated using year-end constant prices and costs and be disclosed net of royalties. The Company has also provided these reserves and their associated values using forecast prices and costs as well as before royalties as additional voluntary information. 5. "Proved" reserves were evaluated using SEC standards and are those quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. SEC standards require that these be evaluated using year-end constant prices and costs and be disclosed net of royalties. The Company has also provided these reserves and their associated values using forecast prices and costs as well as before royalties as additional voluntary information. 6. "Total Proved and Probable" reserves were evaluated using the COGEH standards of NI 51-101 and are those reserves where there is at least a 50 per cent probability that the quantities actually recovered will equal or exceed the stated values. The Company has elected to disclose proved plus probable reserves and their associated values using both constant prices and costs as well as forecast prices and costs and has disclosed these before and net of royalties. The calculation of a probable reserves and value component by subtracting the proved reserves from the proved plus probable reserves may be subject to error due to the different standards applied in the determination of each value. The impact, however, is not material. 7. Canadian securities legislation and policies permit the disclosure, which is included or incorporated by reference herein under a multi-jurisdicitional disclosure system adopted by the SEC, of probable reserves which may not be disclosed in registration statements otherwise filed with the SEC. Probable reserves are generally believed to be less likely to be recovered than proved reserves. The reserve estimates, included or incorporated by reference in this Annual Information Form could be materially different from the quantities and values ultimately realized. 8. All values are shown in Canadian dollars. 23 9. The constant price and cost case assumes that prices in effect at the end of the year adjusted for quality and transportation as well as the 2003 costs are held constant over life. The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the Evaluation Report. Product prices have not been escalated beyond 2004. In addition, operating and capital costs have not been increased on an inflationary basis. The crude oil and natural gas constant prices used in the Evaluation Reports are as follows:
NATURAL GAS CRUDE OIL & NGLs --------------------------------------------- ------------------------------------------------ HARDISTY COMPANY COMPANY HEAVY NORTH AVERAGE HENRY HUB HUNTINGDON/ AVERAGE WTI @ 12(DEGREE) EDMONTON SEA PRICE LOUISIANA AECO SUMAS PRICE CUSHING(i) API PAR(ii) BRENT YEAR $CDN/MCF $US/MMBTU $CDN/MMBTU $CDN/MMBTU $CDN/BBL $US/BBL $CDN/BBL $CDN/BBL $US/BBL - ---- -------- --------- ---------- ---------- -------- ------- -------- -------- ------- 2004 6.63 5.80 6.88 6.94 31.82 32.56 26.16 40.68 30.14
(i) "WTI @ Cushing" refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma. (ii) "Edmonton Par Price" refers to the price of light gravity (40o API), low sulphur content crude oil at Edmonton, Alberta. (iii) Foreign exchange rate used was $0.77 US / $1.00 Cdn. 10. The forecast price and cost cases assume the continuance of current laws and regulations, and any increases in wellhead selling prices also take inflation into account. Sales prices are based on reference prices as detailed below and adjusted for quality and transporation. Subsequent to 2015, reference prices and costs are escalated at 1.5 per cent per year. Future crude oil, natural gas liquids and natural gas price forecasts were based on Sproule's January 1, 2004 crude oil, natural gas liquids and natural gas pricing model. The crude oil and natural gas forecast prices used in the Evaluation Reports are as follows:
NATURAL GAS CRUDE OIL & NGLs --------------------------------------------- ------------------------------------------------ HARDISTY COMPANY COMPANY HEAVY NORTH AVERAGE HENRY HUB HUNTINGDON/ AVERAGE WTI @ 12(DEGREE) EDMONTON SEA PRICE LOUISIANA AECO SUMAS PRICE CUSHING API PAR BRENT YEAR $CDN/MCF $US/MMBTU $CDN/MMBTU $CDN/MMBTU $CDN/BBL $US/BBL $CDN/BBL $CDN/BBL $US/BBL - ---- -------- --------- ---------- ---------- -------- ------- -------- -------- ------- 2004 5.80 5.32 6.04 6.10 29.27 29.63 23.80 37.99 27.63 2005 5.18 4.81 5.36 5.52 26.55 26.80 21.28 34.24 25.27 2006 4.63 4.39 4.80 5.06 25.89 25.76 20.80 32.87 24.21 2007 4.68 4.46 4.91 5.17 26.28 26.14 21.33 33.37 24.57 2008 4.73 4.52 4.98 5.24 26.64 26.53 21.84 33.87 24.94 2009 4.80 4.59 5.05 5.31 26.47 26.93 22.31 34.38 25.32 2010 4.92 4.66 5.14 5.40 26.37 27.34 22.80 34.90 25.70 2011 5.02 4.73 5.24 5.50 26.65 27.75 23.29 35.43 26.08 2012 5.11 4.80 5.33 5.59 26.60 28.16 23.79 35.96 26.47 2013 5.18 4.87 5.43 5.69 26.80 28.58 24.29 36.50 26.87 2014 5.29 4.95 5.52 5.78 27.78 29.01 24.81 37.05 27.27 2015 5.34 5.02 5.62 5.88 28.13 29.45 25.33 37.61 27.68
(i) Foreign exchange rate used was $0.75 US / $1.00 Cdn throughout the forecast 11. Estimated future net revenue from all assets is income derived from the sale of net reserves of crude oil, natural gas and natural gas liquids, less all capital costs, production taxes, and operating costs and before provision for income taxes, administrative overhead costs and existing asset abandonment liabilities. 24 12. The estimated total development capital costs net to the Company necessary to achieve the estimated future net "proved" and "proved and probable" production revenues are:
PROVED PROVED AND PROBABLE ---------------------------------------------------------------------------------------------- FORECAST PRICE CASE CONSTANT PRICE CASE FORECAST PRICE CASE CONSTANT PRICE CASE ($Millions) ($Millions) ($Millions) ($Millions) ------------------- ------------------- ------------------- ------------------- 2004 895 894 1,027 1,026 2005 651 639 986 971 2006 229 221 512 501 2007 197 187 226 219 2008 191 179 323 290 2009 86 78 121 110 2010 60 55 96 88 2011 58 52 166 150 2012 42 37 43 38 2013 28 24 178 156 2014 3 2 3 2 2015 1 1 14 11 Thereafter 181 148 348 286
13 Estimated future net revenue includes the value of the Company's midstream assets which is estimated to be $638.9 million undiscounted and $313.4 million, $243.1 million and $197.3 million discounted at 10%, 15% and 20% respectively. 14. The Evaluation Reports involved data supplied by the Company with respect to quality, heating value and transportation adjustments, interests owned, royalties payable, operating costs and contractual commitments. This data was audited by Sproule against corporate financial statements and was found to have no material differences. No field inspection was conducted. A report on reserves data by Sproule and a report of the Company's management and directors on oil and natural gas disclosure are provided in Schedules A and B, respectively, to this Annual Information Form. The Company does not file estimates of its total oil and natural gas reserves with any U. S. agency or federal authority other than the SEC. 25 C. RECONCILIATION OF CHANGES IN NET RESERVES The following table summarizes the changes during the past year in reserves after deduction of royalties payable to others and using constant prices and costs:
----------------------------------------------- ------------------------------------------------- CRUDE OIL AND NATURAL GAS LIQUIDS (MMBBLS) NATURAL GAS (BCF) OFFSHORE OFFSHORE NORTH NORTH WEST NORTH NORTH WEST AMERICA SEA AFRICA TOTAL AMERICA SEA AFRICA TOTAL ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- PROVED RESERVES Reserves, December 31, 2002 571 202 75 848 2,446 71 71 2,588 Extensions and discoveries 1 -- 13 14 58 -- 6 64 Infill Drilling 54 -- -- 54 243 -- -- 243 Improved Recovery 9 -- -- 9 8 -- -- 8 Property purchases 7 27 -- 34 50 19 -- 69 Property disposals -- -- -- -- (3) -- -- (3) Production (56) (21) (4) (81) (355) (17) (3) (375) Revisions of prior estimates 2 14 1 17 (21) (11) (10) (42) ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------ Reserves, December 31, 2003 588 222 85 895 2,426 62 64 2,552 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- TOTAL PROVED AND PROBABLE RESERVES Reserves, December 31, 2002 636 277 121 1,034 2,765 89 90 2,944 Extensions and discoveries 1 -- 17 18 72 -- 11 83 Infill Drilling 58 -- -- 58 285 -- -- 285 Improved Recovery 25 -- 12 37 26 -- (6) 20 Property purchases 10 33 -- 43 59 22 -- 81 Property disposals -- -- -- -- (3) -- -- (3) Production (56) (21) (4) (81) (355) (17) (3) (375) Revisions of prior estimates 183 28 (13) 198 70 8 (20) 58 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------ Reserves, December 31, 2003 857 317 133 1,307 2,919 102 72 3,093 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------
Information on the Company's oil and natural gas reserves is provided in accordance with United States FAS 69, "Disclosures About Oil and Gas Producing Activities" in the Company's 2003 Annual Report under "Supplementary Oil and Gas Information" on pages 82 to 85 and is incorporated herein by reference. 26 D. CRUDE OIL AND NATURAL GAS PRODUCTION The Company's working interest share of oil, NGLs and natural gas production and revenues received for the last three financial years is summarized in the following tables: YEAR ENDED DECEMBER 31 --------------------------------------- 2003 2002 2001 ---- ---- ---- Daily Production Crude Oil and NGLs (bbls/d) 242,392 215,335 206,323 Natural Gas (MMcf/d) 1,298.7 1,232.3 918.1 Annual Production Crude Oil and NGLs (Mbbls) 88,473 78,597 75,308 Natural Gas (Bcf) 474.0 449.8 355.1
NETBACKS INFORMATION BY QUARTER YEAR 2003 YEAR 2002 ----------------------------------------------- ----------------------------------------------- 1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- ------- ------- ------- ------- ----- PRODUCT NETBACKS Crude oil and NGLs ($/bbl) Sales Price $35.26 $30.27 $30.97 $30.02 $31.59 $24.50 $28.27 $33.57 $31.10 $29.76 Royalties $ 3.56 $ 2.78 $ 2.56 $ 2.22 $ 2.77 $ 2.28 $ 3.02 $ 3.56 $ 3.53 $ 3.16 Production Expenses $10.79 $10.80 $10.14 $ 9.45 $10.28 $ 7.81 $ 7.95 $ 8.67 $ 9.10 $ 8.45 NETBACK $20.91 $16.69 $18.27 $18.35 $18.54 $14.41 $17.30 $21.34 $18.47 $18.15 Natural Gas ($/Mcf) Sales Price $7.25 $6.12 $5.50 $5.23 $6.02 $3.06 $3.68 $3.13 $5.00 $3.76 Royalties $1.78 $1.35 $1.11 $1.05 $1.32 $0.55 $0.77 $0.67 $1.09 $0.78 Production Expenses $0.57 $0.59 $0.63 $0.63 $0.60 $0.58 $0.57 $0.55 $0.57 $0.57 NETBACK $4.90 $4.18 $3.76 $3.55 $4.10 $1.93 $2.34 $1.91 $3.34 $2.41 CRUDE OIL AND NGL NETBACKS BY TYPE Light/Pelican Lake/NGLs ($/bbl) Sales Price $41.51 $34.53 $35.75 $36.20 $36.97 $28.58 $31.84 $36.58 $36.38 $33.84 Royalties $ 4.18 $ 3.32 $ 3.11 $ 2.82 $ 3.35 $ 3.25 $ 4.04 $ 4.48 $ 4.39 $ 4.10 Production Expenses $10.42 $ 9.76 $ 9.53 $ 9.65 $ 9.83 $ 7.48 $ 8.36 $10.06 $ 9.38 $ 8.97 NETBACK $26.91 $21.45 $23.11 $23.73 $23.79 $17.85 $19.44 $22.04 $22.61 $20.77 Heavy ($/bbl) Sales Price $26.63 $24.56 $24.46 $22.14 $24.39 $20.01 $24.20 $29.78 $24.54 $24.89 Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00 $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03 Production Expenses $11.30 $12.19 $10.96 $ 9.19 $10.88 $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84 Netback $12.62 $10.31 $11.67 $11.48 $11.51 $10.62 $14.86 $20.45 $13.32 $15.02
NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. 27
NETBACKS INFORMATION BY QUARTER YEAR 2003 YEAR 2002 ----------------------------------------------- ----------------------------------------------- 1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- ------- ------- ------- ------- ----- SEGMENTED NORTH AMERICA PRODUCT NETBACKS Light/Pelican Lake/NGLs ($/bbl) Sales Price $35.08 $32.01 $31.97 $31.64 $32.69 $25.27 $28.90 $32.83 $31.94 $30.01 Royalties $ 7.65 $ 6.33 $ 6.04 $ 5.51 $ 6.39 $ 4.24 $ 5.11 $ 5.98 $ 5.81 $ 5.35 Production Expenses $ 6.09 $ 6.42 $ 6.76 $ 7.24 $ 6.62 $ 5.25 $ 5.30 $ 5.00 $ 5.28 $ 5.20 NETBACK $21.34 $19.26 $19.17 $18.89 $19.68 $15.78 $18.49 $21.85 $20.85 $19.46 Heavy ($/bbl) Sales Price $26.63 $24.56 $24.46 $22.14 $24.39 $20.01 $24.20 $29.78 $24.54 $24.89 Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00 $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03 Production Expenses $11.30 $12.19 $10.96 $ 9.19 $10.88 $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84 NETBACK $12.62 $10.31 $11.67 $11.48 $11.51 $10.62 $14.86 $20.45 $13.32 $15.02 Natural Gas ($/Mcf) Sales Price $7.36 $6.25 $5.62 $5.32 $6.14 $3.05 $3.72 $3.15 $5.04 $3.78 Royalties $1.84 $1.40 $1.16 $1.10 $1.38 $0.57 $0.79 $0.69 $1.11 $0.80 Production Expenses $0.55 $0.56 $0.58 $0.60 $0.57 $0.56 $0.55 $0.52 $0.55 $0.55 NETBACK $4.97 $4.29 $3.88 $3.62 $4.19 $1.92 $2.38 $1.94 $3.38 $2.43 NORTH SEA PRODUCT NETBACKS Light Oil ($/bbl) Sales Price $50.27 $37.83 $39.84 $41.93 $42.43 $33.75 $39.36 $41.68 $41.83 $39.79 Royalties $ 0.11 ($0.19) $ 0.09 ($0.15) ($0.03) $ 1.54 $ 1.76 $ 2.56 $ 2.79 $ 2.30 Production Expenses $15.50 $14.17 $13.25 $13.42 $14.07 $10.09 $15.72 $18.30 $14.68 $15.06 NETBACK $34.66 $23.85 $26.50 $28.66 $28.39 $22.12 $21.88 $20.82 $24.36 $22.43 Natural Gas ($/Mcf) Sales Price $4.03 $2.21 $2.57 $3.32 $3.03 $3.77 $1.80 $1.98 $3.20 $2.75 Royalties -- -- -- -- -- -- -- -- -- -- Production Expenses $1.09 $1.45 $1.60 $1.16 $1.33 $1.33 $1.90 $1.78 $1.25 $1.53 NETBACK $2.94 $0.76 $0.97 $2.16 $1.70 $2.44 ($0.10) $0.20 $1.95 $1.22 OFFSHORE WEST AFRICA PRODUCT NETBACKS Light Oil ($/bbl) Sales Price $37.86 $34.34 $37.37 $36.42 $36.47 $37.61 $33.92 $42.78 $43.15 $40.10 Royalties $1.20 $0.99 $1.13 $1.03 $1.08 $1.65 $1.11 $1.34 $1.35 $1.35 Production Expenses $14.03 $9.32 $7.11 $6.67 $8.68 $18.62 $12.76 $11.23 $13.68 $13.63 NETBACK $22.63 $24.03 $29.13 $28.72 $26.71 $17.34 $20.05 $30.21 $28.12 $25.12 Natural Gas ($/Mcf) Sales Price $3.80 $5.09 $4.59 $3.95 $4.37 -- -- $4.97 $4.63 $4.82 Royalties $0.11 $0.15 $0.14 $0.11 $0.13 -- -- $0.15 $0.15 $0.15 Production Expenses $2.37 $1.45 $1.24 $1.18 $1.39 -- -- $1.77 $1.85 $1.81 NETBACK $1.32 $3.49 $3.21 $2.66 $2.85 $ -- $ -- $3.05 $2.63 $2.86
NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. 28 NETBACKS INFORMATION BY QUARTER
YEAR 2001 --------------------------------------------------------------- 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- AVERAGE DAILY PRODUCTION VOLUMES Crude Oil and NGLs (bbls) 205,588 214,716 207,065 198,000 206,323 Natural Gas (Mcf) 850.8 884.6 923.8 1,011.6 918.1 PRODUCT NETBACKS Crude oil and NGLs ($/bbl) Sales Price $22.06 $25.32 $28.37 $21.28 $24.31 Royalties 2.36 2.42 2.47 1.41 2.17 Production Expenses 8.18 7.57 7.29 7.52 7.64 NETBACK $11.52 $15.33 $18.61 $12.35 $14.50 NATURAL GAS ($/MCF) Sales Price $9.30 $5.93 $3.12 $2.94 $5.16 Royalties 2.40 1.47 0.67 0.62 1.25 Production Expenses 0.50 0.50 0.50 0.53 0.51 NETBACK $6.40 $3.96 $1.95 $1.79 $3.40 CRUDE OIL AND NGL NETBACKS BY TYPE Light/Pelican Lake/NGLs ($/bbl) Sales Price $30.96 $33.59 $32.75 $26.95 $31.13 Royalties 4.03 3.86 3.30 2.29 3.38 Production Expenses 5.99 6.10 6.12 7.15 6.34 NETBACK $20.94 $23.63 $23.33 $17.51 $21.41 HEAVY ($/BBL) Sales Price $12.76 $15.83 $23.21 $14.85 $16.63 Royalties 0.61 0.77 1.50 0.43 0.83 Production Expenses 10.48 9.24 8.68 7.93 9.10 Netback $1.67 $5.82 $13.03 $6.49 $6.70 NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. SEGMENTED NORTH AMERICA PRODUCT NETBACKS YEAR 2001 --------------------------------------------------------------- 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- Light/Pelican Lake/NGLs ($/bbl) Sales Price $27.04 $27.49 $29.95 $23.83 $27.10 Royalties 4.57 5.04 4.17 2.79 4.16 Production Expenses 3.84 4.02 4.22 4.74 4.19 NETBACK $18.63 $18.43 $21.56 $16.30 $18.75 Heavy ($/bbl) Sales Price $12.76 $15.83 $23.21 $14.85 $16.63 Royalties 0.61 0.77 1.50 0.43 0.83 Production Expenses 10.48 9.24 8.68 7.93 9.10 NETBACK $1.67 $5.82 $13.03 $6.49 $6.70 Natural Gas ($/Mcf) Sales Price $9.30 $5.99 $3.13 $2.94 $5.19 Royalties 2.40 1.49 0.68 0.63 1.26 Production Expenses 0.50 0.50 0.50 0.52 0.50 NETBACK $6.40 $4.00 $1.95 $1.79 $3.43 NORTH SEA PRODUCT NETBACKS Light Oil ($/bbl) Sales Price $41.04 $43.07 $37.28 $33.39 $38.66 Royalties $2.86 $2.23 $1.97 $1.52 $2.10 Production Expenses $9.22 $8.42 $8.09 $10.54 $9.00 NETBACK $28.96 $32.42 $27.22 $21.33 $27.56 Natural Gas ($/Mcf) Sales Price $ -- $ 1.74 $ 2.51 $ 3.00 $ 2.51 Royalties $ -- $ -- $ -- $ -- $ -- Production Expenses $ -- $ 0.61 $ 0.74 $ 1.34 $ 0.94 NETBACK $ -- $ 1.13 $ 1.77 $ 1.66 $ 1.57
29 OFFSHORE WEST AFRICA PRODUCT NETBACKS
YEAR 2001 --------------------------------------------------------------- 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- Light Oil ($/bbl) Sales Price $40.58 $39.75 $34.66 $19.56 $33.57 Royalties $ -- $ 0.65 $ 2.03 $ 0.64 $ 0.93 Production Expenses $38.80 $17.23 $19.05 $19.15 $21.77 NETBACK $ 1.78 $21.87 $13.58 $(0.23) $10.87 Natural Gas ($/Mcf) Sales Price -- -- -- -- -- Royalties -- -- -- -- -- Production Expenses -- -- -- -- -- NETBACK $ -- $ -- $ -- $ -- $ --
E. HISTORICAL DRILLING ACTIVITY BY PRODUCT The following table sets forth the gross and net wells in which the Company has participated for the period indicated: YEAR ENDED DECEMBER 31 --------------------------------------------------- 2003 2002 ------------------------ ------------------------ GROSS NET GROSS NET ----- --- ----- --- Natural Gas 841 777 183 162 Crude Oil 490 458 316 264 Service/Stratigraphic 447 440 456 447 Dry Holes 126 118 32 27 ------------------------ ------------------------ Total 1,904 1,793 987 900 ======================== ======================== *Total Success Rate 91% 94% *excluding service and stratigraphic test wells 30 F. CAPITAL EXPENDITURES Costs incurred by the Company in respect of its programs of acquisition and disposition, and exploration and development of crude oil and natural gas properties, are summarized in the following tables: YEAR ENDED DECEMBER 31 ------------------------------------- 2003 2002 ---------------- --------------- Corporate acquisition -- 2,393 Net property acquisitions 336 440 Land acquisition and retention 154 114 Seismic evaluation 77 63 Well drilling, completion and equipping 1,194 626 Pipeline and production facilities 522 292 ---------------- --------------- Reserve replacement expenditures 2,283 3,928 Midstream operations 11 20 Horizon Project 152 68 Abandonments 40 43 Head office equipment 20 10 ---------------- --------------- Total Net Capital Expenditures 2,506 4,069 ================ =============== 31
2003 THREE MONTHS ENDED --------------------------------------------------------------------- ($ Millions) CAPITAL EXPENDITURES BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ------- ------- -------- ------- Corporate acquisition -- -- -- -- Net property acquisitions 178 23 106 29 Land acquisition and retention 21 36 53 44 Seismic evaluation 19 21 12 25 Well drilling, completion and equipping 396 190 256 352 Pipeline and production facilities 149 107 133 133 ------- ------- -------- ------- Reserve replacement expenditures 763 377 560 583 Midstream operations 3 1 5 2 Horizon Project 41 27 32 52 Abandonments 3 3 14 20 Head office equipment 3 2 10 5 ------- ------- -------- ------- Total Net Capital Expenditures 813 410 621 662 ===================================================================== 2002 THREE MONTHS ENDED --------------------------------------------------------------------- ($ Millions) CAPITAL EXPENDITURES BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ------- ------- -------- ------- Corporate acquisition -- -- 2,393 -- Net property acquisitions 35 33 333 39 Land acquisition and retention 28 19 48 18 Seismic evaluation 25 14 5 19 Well drilling, completion and equipping 207 136 144 139 Pipeline and production facilities 124 67 56 45 ------- ------- -------- ------- Reserve replacement expenditures 419 269 2,979 260 Midstream operations 10 5 -- 6 Horizon Project 22 17 10 19 Abandonments 7 12 20 4 Head office equipment 1 2 4 3 ------- ------- -------- ------- Total Net Capital Expenditures 459 305 3,013 292 =====================================================================
32 G. NON-RESERVE ACREAGE The following table summarizes the Company's working interest holdings in core area non-reserve acreage as at December 31, 2003: GROSS ACRES NET ACRES ----------- --------- (thousands) (thousands) NORTH AMERICA Alberta 9,304 7,859 British Columbia 2,011 1,560 Saskatchewan 449 380 Manitoba 12 12 NORTH SEA United Kingdom 804 573 France 2,693 1,347 OFFSHORE WEST AFRICA Angola 1,220 610 Cote d'Ivoire 452 333 5,550 5,550 South Africa --------------- -------------- Total 22,495 18,224 =============== ============== H. DEVELOPED ACREAGE The following table summarizes the Company's working interest holdings in core region developed acreage as at December 31, 2003: GROSS ACRES NET ACRES ----------- --------- (thousands) (thousands) NORTH AMERICA Alberta 4,361 3,415 British Columbia 605 461 Saskatchewan 295 156 Manitoba 5 4 NORTH SEA United Kingdom 106 65 France -- -- OFFSHORE WEST AFRICA Angola -- -- Cote d'Ivoire 8 5 South Africa -- -- --------------- -------------- Total 5,380 4,106 =============== ============== 33 SELECTED FINANCIAL INFORMATION The following table summarizes the consolidated financial statements of the Company, which follows the full cost method of accounting for crude oil and natural gas operations:
----------------------------------------- YEAR ENDED DECEMBER 31 ----------------------------------------- 2003 2002 ---- ---- ($ millions, except per share information) Revenues (1) (net of royalties) 5,100 3,742 Cash flow from operations attributable to common shareholders 3,160 2,254 Per common share - basic 23.54 17.63 - diluted 23.06 16.99 Net earnings attributable to common shareholders 1,407 570 Per common share - basic 10.48 4.46 - diluted 10.14 4.31 Total assets 14,198 13,359 Total long-term debt(2) 2,645 4,074
--------------------------------------------------------------------------------- 2003 THREE MONTHS ENDED --------------------------------------------------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- ($ millions, except per share information) Revenues (1) (net of royalties) 1,407 1,254 1,244 1,195 Net earnings attributable to 428 525 203 251 common shareholders Per common share - basic 3.19 3.91 1.51 1.87 - diluted 3.03 3.78 1.49 1.83 --------------------------------------------------------------------------------- 2002 THREE MONTHS ENDED --------------------------------------------------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- ($ millions, except per share information) Revenues (1) (net of royalties) 690 797 1,072 1,183 Net earnings attributable to 99 145 117 209 common shareholders Per common share - basic 0.81 1.18 0.88 1.56 - diluted 0.79 1.09 0.86 1.51
(1) Restated to exclude transportation costs from revenue. (2) Excluding current portion of ling-term debt. 34 MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES The Company's common shares are listed and posted for trading on Toronto Stock Exchange and the New York Stock Exchange under the symbol CNQ. On January 17, 2001, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, beginning January 22, 2001 and ending January 21, 2002, to purchase for cancellation up to 6,114,726 common shares of the Company, being 5 per cent of the 122,294,533 common shares of the Company outstanding on January 17, 2001. During this period, 2,537,800 common shares were purchased for cancellation at an average price of $44.61. On January 21, 2002, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, beginning January 23, 2002 and ending January 22, 2003, to purchase for cancellation up to 6,060,180 common shares of the Company, being 5 per cent of the 121,203,603 common shares of the Company outstanding on January 18, 2002. No common shares were purchased during this program. In January 2002, the Company issued 60,000 flow-through common shares at a price of $39.00 per common share. The value of the common shares was determined as the closing market price on Toronto Stock Exchange on the day prior to the allotment of the common shares. On January 22, 2003, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, beginning January 24, 2003 and ending January 23, 2004, to purchase for cancellation up to 6,692,799 common shares of the Company, being 5 per cent of the 133,855,988 common shares of the Company outstanding on January 17, 2003. Under this program, the Company purchased a total of 2,734,800 common shares for cancellation at an average purchase price of $52.51 for each common share purchased. On January 22, 2004, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, commencing January 24, 2004 and ending January 23, 2005, to purchase for cancellation up to 6,690,385 common shares of the Company, being 5 per cent of the 133,807,695 common shares of the Company outstanding on January 13, 2004. On February 19, 2004, the Board of Directors passed a resolution proposing an amendment to the Articles of the Company to split the issued and outstanding Common Shares of the Company on a two-for-one basis subject to shareholder approval at the Annual and Special Meeting of Shareholders scheduled for May 6, 2004. DIVIDEND HISTORY The dividend policy of the Company undergoes a periodic review by the Board of Directors and is subject to change at any time depending upon the earnings of the Company, its financial requirements and other factors existing at the time. Prior to 2001, dividends had not been paid on the common shares of the Company. On January 17, 2001 the Board of Directors approved a dividend policy for the payment of a regular quarterly dividend of $0.10 per common share. On February 25, 2002 the Board of Directors approved an increase in the quarterly dividend to $0.125 per common share commencing with the dividend payable April 1, 2002. On February 35 20, 2003 the Board of Directors approved a further increase in the quarterly dividend to $0.15 per common share commencing with the dividend payable April 1, 2003. The Board of Directors reviewed the dividend payments for 2004 and on February 19, 2004 the Board of Directors approved a 33 per cent increase in the quarterly dividend to $0.20 per common share commencing with the dividend payable April 1, 2004. Dividends have been paid on the first day of January, April, July and October of each year since 2001. DIRECTORS AND OFFICERS The names, municipalities of residence, offices held with the Company and principal occupations of the directors and officers of the Company are set forth below:
POSITION PRINCIPAL PRESENTLY OCCUPATION NAME HELD DURING PAST 5 YEARS Catherine M. Best Director(2) Senior Vice-President, Risk Management and Chief Financial Calgary, Alberta (age 50) Officer of the Calgary Health Region from 2002 to present, Vice-President, Corporate Services and Chief Financial Officer of the Calgary Health Region from February 2000 to 2002; prior thereto with Ernst & Young since 1980, most recently as a Corporate Audit Partner from 1991 to 2000. Has served continuously as a director since November 2003. N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (a private Calgary, Alberta Director(3)(5) management and consulting company). Has served (age 44) continuously as a director of the Company since September 1988. Currently serving on the board of directors of Ensign Resource Service Group Inc.; Magellan Aerospace Corporation; and, Penn West Petroleum Ltd. Ambassador Gordon D. Giffin Director(1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm) Atlanta, Georgia (age 54) since May 2001; prior thereto United States Ambassador to Canada. Has served continuously as a director of the Company since May 2002. Currently serving on the board of directors of Bowater, Inc.; Canadian National Railway; Canadian Imperial Bank of Commerce; and, Transalta Corporation. James T. Grenon Director(2)(4) Managing Director, TOM Capital Associates Inc. (a private Calgary, Alberta (age 47) investment company). Has served continuously as a director of the Company since September 1988. Currently serving on the board of trustees for Foremost Industries Income Fund. John G. Langille President and Director Officer of the Company. Has served continuously as a Calgary, Alberta (age 58) director of the Company since June 1982. Keith A.J. MacPhail Director(3)(5) Chairman, President and Chief Executive Officer, Bonavista Calgary, Alberta (age 47) Petroleum Ltd. (independent oil and natural gas company) since November 1997 and Chairman, NuVista Energy Ltd since July 2003. Has served continuously as a director of the Company since October 1993. Currently serving on the board of directors of Bonavista Petroleum Ltd., Bonavista Energy Trust and NuVista Energy Ltd. Allan P. Markin Chairman and Director Chairman of the Company. Has served continuously as a Calgary, Alberta (age 58) director of the Company since January 1989. James S. Palmer, C.M., A. O. Director(1)(2)(3)(4) Chairman, Burnet, Duckworth & Palmer LLP (law firm). Has E., Q.C. (age 75) served continuously as a director of the Company since May Calgary, Alberta 1997. Currently serving on the board of directors of Magellan Aerospace Corporation; Trenton Iron Works; Rally Energy Corp.; and, on the board of trustees for Rogers Sugar Income Fund.
36
POSITION PRINCIPAL PRESENTLY OCCUPATION NAME HELD DURING PAST 5 YEARS Dr. Eldon R. Smith, M.D. Director(4)(5) Professor and Former Dean, Faculty of Medicine, The Calgary, Alberta (age 64) University of Calgary. Has served continuously as a director of the Company since May 1997. Currently serving on the board of directors of Vasogen Inc.; Pheromone Sciences Corp.; and, Biomax Technologies Inc. David A. Tuer Director(1)(3) President and CEO of Hawker Resources Inc. (independent Calgary, Alberta (age 54) oil and natural gas company) since January 2003 and Chairman, Calgary Health Region since October 2001. Prior thereto President and Chief Executive Officer, PanCanadian Energy Corporation. Has served continuously as a director of the Company since May 2002. Currently serving on the board of directors of Hawker Resources Inc.; Rockwater Capital Corporation; Ultima Energy Trust; and, Argo Energy Ltd Steve W. Laut Chief Operating Officer Officer of the Company Calgary, Alberta (age 46) Real M. Cusson Senior Vice-President, Officer of the Company Calgary, Alberta Marketing (age 53) Real J. H. Doucet Senior Vice-President, Officer of the Company since October 2000; prior thereto Calgary, Alberta Oil Sands director of various divisions at Suncor Inc. since 1993. (age 51) Allen M. Knight Senior Vice-President, Officer of the Company Calgary, Alberta International & Corporate Development (age 54) Tim S. McKay Senior Vice-President, Officer of the Company Calgary, Alberta Operations (age 42) Douglas A. Proll Senior Vice-President, Officer of the Company since April 2001; prior thereto Calgary, Alberta Finance Vice President Finance and Treasurer of Renaissance Energy (age 53) Ltd. until August 2000 and most recently Vice President Finance and Business Development of Husky Energy Inc. from August 2000 to February 2001. Lyle G. Stevens SeniorVice-President, Officer of the Company Calgary, Alberta Exploitation (age 49) Mary-Jo Case Vice-President, Land Officer of the Company since May 2002; prior thereto Calgary, Alberta (age 45) Co-ordinator Land at PanCanadian Petroleum Limited 1994 to 1999 and most recently Manager Commercial Ventures and Land at PanCanadian Petroleum Limited 1999 to 2002. William R. Clapperton Vice-President, Officer of the Company since January 2002; prior thereto Calgary, Alberta Regulatory, Stakeholder Manager, Surface Land and Environment for the Company. and Environmental Affairs (age 41) Gordon M. Coveney Vice-President, Officer of the Company since September 2003; prior thereto Calgary, Alberta Exploration, Northeast Exploration Manager for the Company. District (age 50) Cameron S. Kramer Vice-President, Officer of the Company since September 2002; prior thereto Calgary, Alberta Field Operations Production Engineer of the Company until March 2000 and (age 36) most recently Manager, Field Operations of the Company from April 2000 to September 2002.
37
POSITION PRINCIPAL PRESENTLY OCCUPATION NAME HELD DURING PAST 5 YEARS Leon Miura Vice-President, Upgrading Officer of the Company since August 2003; prior thereto Calgary, Alberta (age 49) from 1978 to 2003 held progressively senior positions at Petroleos de Venezuela including Cerro Negro Execution Manager, Heavy Oil Upgrading from 1997 to 2001 and most recently Nitrogen Injection Project Director, Secondary Recovery at Petroleos de Venezuela 2002 to 2003. J. Kevin Stromquist Vice-President, Officer of the Company since September 2003, prior thereto Calgary, Alberta Exploration, Northwest Exploration Manager for the Company. Alberta (age 44) Jeffrey W. Wilson Vice-President, Officer of the Company since September 2003; prior thereto Calgary, Alberta Exploration, B. C./S. Exploration Manager for the Company. AB. Districts (age 51) Lynn M. Zeidler Vice-President, Bitumen Officer of the Company since August 2003; prior thereto Calgary, Alberta Production from May 1980 to July 2003 held progressively senior (age 47) positions at Shell Canada Limited including on secondment from Shell Canada Limited as Manager-Tier 1 Implementation at Sable Offshore Energy Inc January 1998 to September 2000 and most recently General Project Manager, Athahasca Oil Sands Project at Shell Canada Limited October 2000 to May 2003 and concurrently as Vice President & Project Director, Muskeg River Mine at Albian Sands Energy Inc. May 2002 to July 2003 and General Manager Claims Athabasca Oil Sands Project at Shell Canada Limited May 2003 to July 2003. Bruce E. McGrath Corporate Secretary Officer of the Company Calgary, Alberta (age 54)
(1) Member of the Nominating and Corporate Governance Committee (2) Member of the Audit Committee (3) Member of the Reserves Committee (4) Member of the Compensation Committee (5) Member of the Safety, Health and Environmental Committee All directors stand for election at each Annual General Meeting of CNRL shareholders. With the exception of Ms. C. M. Best who was appointed to the Board effective November 17, 2003, all of the current directors were elected to the Board at the last annual meeting of shareholders held on May 8, 2003. All of the current directors are standing for election at the Annual and Special Meeting of Shareholders scheduled for May 6, 2004. There are potential conflicts of interest to which the directors and officers of the Company may become subject in connection with the operations of the Company. Some of the directors and officers have been and will continue to be engaged in the identification and evaluation of businesses and assets with a view to potential acquisition of interests on their own behalf and on behalf of other corporations, and situations may arise where the directors and officers will be in direct competition with the Company. Conflicts, if any, will be subject to the procedures and remedies under the BUSINESS CORPORATIONS ACT (Alberta). As at December 31, 2003, the directors and officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, in the aggregate, approximately 5 per cent of the total outstanding common shares (approximately 6 per cent after the exercise of options held by them pursuant to the Company's stock option plan). 38 ADDITIONAL INFORMATION Additional information including Directors' and Executive Officers' remuneration, principal holders of the Company's securities, options to purchase the Company's securities and interest of insiders in material transactions is contained in the Company's Notice of Annual and Special Meeting and Information Circular dated March 25, 2004 in connection with the Annual and Special Meeting of Shareholders of CNRL to be held on May 6, 2004 which information is incorporated herein by reference. Additional financial information and discussion of the affairs of the Company and the business environment in which the Company operates is provided in the Company's Management Discussion and Analysis, comparative Consolidated Financial Statements and Supplementary Oil & Gas Information for the most recently completed fiscal year ended December 31, 2003 found on pages 38 to 59, 60 to 81 and 82 to 85 respectively, of the 2003 Annual Report to the Shareholders, which information is incorporated herein by reference. The Company shall provide to any person, upon request to the Corporate Secretary of the Company: (a) when securities of the Company are in the course of distribution pursuant to a short form prospectus or a preliminary short form prospectus has been filed in respect of a distribution of its securities, (i) one copy of the Annual Information Form of the Company, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form, (ii) one copy of the comparative consolidated financial statements of the Company for its most recently completed financial year together with the accompanying report of the auditor and one copy of any interim consolidated financial statements of the issuer subsequent to the consolidated financial statements for its most recently completed financial year, (iii) one copy of the information circular of the Company in respect of its most recent annual meeting of shareholders that involved the election of directors or one copy of any annual filing prepared in lieu of that information circular, as appropriate, and (iv) one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and are not required to be provided under (i) to (iii) above; or (b) at any other time, one copy of any other documents referred to in (a)(i), (ii) and (iii) above, provided the Company may require the payment of a reasonable charge if a person who is not a security holder of the issuer makes the request. 39 For additional copies of this Annual Information Form and the materials listed in the preceding paragraphs, please contact: Corporate Secretary of the Corporation at: 2500, 855 - 2nd Street S.W. Calgary, Alberta T2P 4J8 40 SCHEDULE "A" AMENDED FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR REPORT ON RESERVES DATA To the Board of Directors of Canadian Natural Resources Limited (the "Corporation"): 1. We have evaluated the Corporation's reserves data as at December 31, 2003. The reserves data consist of the following: (a) (i) proved oil and natural gas reserves quantities estimated as at December 31, 2003 using constant prices and costs; (ii) the related estimated future net revenue; and (iii) the related standardized measure calculation for proved oil and natural gas reserves quantities. (b) (i) proved and proved plus probable oil and natural gas reserves estimated as at December 31, 2003 using forecast prices and costs; and (ii) the related estimated future net revenue. 2. The reserves data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data based on our evaluation. 3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) with the necessary modifications to reflect definitions and standards under the U.S. Financial Accounting Standards Board policies (the "FASB Standards") and the legal requirements of the U.S. Securities and Exchange Commission ("SEC Requirements"). 4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions as outlined above. 41 5. The following table sets forth the estimated net present value of future cash flows (before deduction of income taxes) attributed to proved oil and gas reserves quantities, estimated using constant prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation's management and board of directors:
- -------------------------------------------------------------------------------------------------------------------- INDEPENDENT DESCRIPTION LOCATION OF RESERVES QUALIFIED AND (COUNTRY OR FOREIGN RESERVES PREPARATION GEOGRAPHIC AREA) NET PRESENT VALUES OF FUTURE CASH FLOWS EVALUATOR OR DATE OF AUDITOR EVALUATION (BEFORE INCOME TAXES, 10% DISCOUNT RATE) REPORT - -------------------------------------------------------------------------------------------------------------------- AUDITED EVALUATED REVIEWED TOTAL MM$ MM$ MM$ MM$ - -------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------- Sproule Sproule North America United 0 $13,015.6 $0 $13,015.6 Evaluated the Kingdom, West Africa 0 $ 2,086.9 $0 $ 2,086.9 P&NG Reserves 0 $ 1,014.9 $0 $ 1,014.9 of CNRL (As of January 1, 2004) - -------------------------------------------------------------------------------------------------------------------- TOTALS $0 $16,117.4 $0 $16,117.4 - --------------------------------------------------------------------------------------------------------------------
6. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook as modified by the FASB Standards and SEC requirements. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. 7. We have no responsibility to update our evaluation for events and circumstances occurring after their respective preparation dates. 42 8. Reserves are estimates only, and not exact quantities. In addition, as the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. Executed as to our report referred to above: February 18, 2004 SPROULE ASSOCIATES LIMITED ORIGINAL SIGNED BY: /s/ Harry J. Helwerda ------------------------------ Harry J. Helwerda, P.Eng., Vice-President, Engineering, Canada and U.S. ORIGINAL SIGNED BY: /s/ R. Keith MacLeod ------------------------------ R. Keith MacLeod, P.Eng. Executive Vice-President ORIGINAL SIGNED BY: /s/ Doug Ho ------------------------------ Doug Ho, P.Eng. Manager, Engineering, and Associate ORIGINAL SIGNED BY: /s/ Ken H. Crowther ------------------------------ Ken H. Crowther, P.Eng. President 43 SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION Management of Canadian Natural Resources Limited (the "Corporation") is responsible for the preparation and disclosure of information with respect to the Corporation's oil and natural gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following: (a) (i) proved oil and natural gas reserve quantities estimated as at December 31, 2003 using constant prices and costs; (ii) the related estimated future net revenue; and (iii) the related standardized measure calculation for proved oil and natural gas reserve quantities. (b) (i) proved and proved plus probable oil and natural gas reserves estimated as at December 31, 2003 using forecast prices and costs; and (ii) the related estimated future net revenue Sproule Associates Limited, an independent qualified reserves evaluator has evaluated the Corporation's reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report. The reserves committee (the "Reserves Committee") of the board of directors (the "Board of Directors") of the Corporation has: (a) reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator; (b) met with the independent qualified reserves evaluator to determine whether any restrictions placed by management affected the ability of the independent qualified reserves evaluator to report without reservation; and (c) reviewed the reserves data with management and the independent qualified reserves evaluator. The Reserves Committee of the Board of Directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and natural gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved: (a) the content and filing with securities regulatory authorities of the reserves data and other oil and natural gas information; 44 (b) the filing of the report of the independent qualified reserves evaluator on the reserves data; and (c) the content and filing of this report. Reserves data are estimates only, and are not exact quantities. In addition, as the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. "Signed" Douglas A. Proll Senior Vice President, Finance "Signed" Steve W. Laut Chief Operating Officer "Signed" David A. Tuer Independent Director, and Chairman of the Reserve Committee "Signed" Keith A.J. MacPhail Independent Director, and Member of the Reserve Committee Dated this 19th day of February, 2004 Calgary, Alberta EX-99 4 ex2-form40f_2003.txt EXHIBIT 2 EXHIBIT 2 --------- - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- Canadian Natural Resources Limited is a Canadian based senior independent energy company engaged in the acquisition, exploration, development, production, marketing and sale of oil and natural gas. The Company initiates, operates and maintains a large working interest in a majority of the prospects in which it participates. The Company's principal core areas of oil and natural gas operations are in the Western Canadian Sedimentary Basin, the United Kingdom sector of the North Sea and Offshore West Africa. [PICTURES OMITTED] [OIL RIGS AND EQUIPMENT] 38 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this document or documents incorporated herein by reference for Canadian Natural Resources Limited (the "Company") may constitute "forward-looking statements" within the meaning of the United States Private Litigation Reform Act of 1995. These forward-looking statements can generally be identified as such because of the context of the statements including words such as the Company "believes","anticipates", "expects", "plans","estimates", or words of a similar nature. The forward-looking statements are based on current expectations and are subject to known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others: the general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; the foreign currency exchange rates; the economic conditions in the countries and regions in which the Company conducts business; the political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the industry capacity; the ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition, availability and cost of seismic, drilling and other equipment; the ability of the Company to complete its capital programs; the ability of the Company to transport its products to market; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas; the availability and cost of financing; the success of exploration and development activities; the timing and success of integrating the business and operations of acquired companies; the production levels; the uncertainty of reserve estimates; the actions by governmental authorities; the government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations); the site restoration costs; and other circumstances affecting revenues and expenses. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors, and management's course of action would depend upon its assessment of the future considering all information then available. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. The Company assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES Management's discussion and analysis includes references to financial measures commonly used in the oil and gas industry, such as cash flow, cash flow per share and EBITDA. These financial measures are not defined by generally accepted accounting principles ("GAAP") and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate the performance of the Company and its business segments. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with Canadian GAAP, as an indication of the Company's performance. MANAGEMENT'S DISCUSSION AND ANALYSIS Management's discussion and analysis of the financial condition and results of operations of the Company should be read in conjunction with the Company's audited consolidated financial statements and related notes for the year ended December 31, 2003. The consolidated financial statements have been prepared in accordance with Canadian GAAP. A reconciliation of Canadian GAAP to United States GAAP is included in note 16 to the consolidated financial statements. All dollar amounts are referenced in Canadian dollars, except where noted otherwise. The calculation of barrels of oil equivalent ("boe") is based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil to estimate relative energy content. Production volumes are the Company's interest before royalties, and realized prices include the effect of derivative financial instruments gains and losses, except where noted otherwise. This conversion may be misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. The following discussion details the Company's 2003 financial results compared to 2002 and 2001, including its capital program, and its outlook for 2004. 39 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- OBJECTIVE AND STRATEGY The Company's objective is to increase cash flow, net earnings, crude oil and natural gas production, reserves and net asset value on a per common share basis through the development of its existing crude oil and natural gas properties and by the discovery and acquisition of new reserves. The Company accomplishes this by having a defined growth and value enhancement plan for each of its products and segments. The Company takes a measured approach to growth and investments and focuses on creating long-term shareholder wealth. The Company effectively allocates its capital by maintaining: o Balance between its products, namely natural gas, light oil, Pelican Lake oil (1), primary heavy oil and thermal heavy oil; o Balance between near-, mid- and long-term projects; o Balance between acquisitions, exploitation and exploration; and o Balance between sources of debt and a strong balance sheet. (1) Pelican Lake oil is 14-17(0) API oil, but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. Strategic acquisitions, such as Rio Alto Exploration Ltd. ("Rio Alto") in 2002, are a key component of the Company's strategy. The Company`s crude oil marketing strategy includes displacing medium sour crude oil from PADD II, supporting and participating in pipeline additions, and encouraging the development of projects that add conversion capacity. Cost control is central to the Company's strategy. By controlling costs consistently throughout all industry cycles, the Company is able to achieve continued growth. Cost control is attained by area knowledge, by core area domination and by operating at a high working interest. The year ended December 31, 2003, was another successful year in the execution of the Company's strategy. Highlights are as follows: o Achieved record levels of cash flow and net earnings; o Reduced long-term debt by $1,269 million through repayments of $740 million and foreign exchange gains of $529 million from the strengthening Canadian dollar; o Achieved the Company's annual production guidance for both natural gas and crude oil and NGLs; o Continued consolidation of the Company's North Sea interests. The Company now operates 99% of its production and owns an average working interest of approximately 80% in its North Sea properties. This provides the Company with the level of operatorship and working interests in the North Sea necessary to effectively control costs; o Awarded major contracts for the Baobab Project, Offshore West Africa; o Completed the Design Basis Memorandum ("DBM") phase of engineering for the Horizon Oil Sands Project ("Horizon Project") and commenced the third and final phase of pre-construction engineering, Engineering Design Specifications ("EDS"); o Completed the Joint Panel review for regulatory approvals of the Horizon Project; and o Purchased 2,734,800 common shares for a total cost of $144 million under the Company's Normal Course Issuer Bid. ACQUISITION OF RIO ALTO In 2002, the Company paid cash of $850 million and issued 10,008,218 common shares to acquire all of the issued and outstanding common shares of Rio Alto by way of a plan of arrangement. This was a strategic acquisition as it increased the Company's natural gas production and added a new natural gas core region in Northwest Alberta. The Rio Alto acquisition is included in the results of operations commencing July 1, 2002. 40 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - --------------------------------------------------------------------------------
CASH FLOW AND NET EARNINGS FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) 2003 2002 2001 - ----------------------------------------------------------------------------------------------------------------- Revenue (1) $ 5,972 $ 4,342 $ 3,757 Cash flow from operations attributable to common shareholders (2) $ 3,160 $ 2,254 $ 1,920 Per common share - basic $ 23.54 $ 17.63 $ 15.83 - diluted $ 23.06 $ 16.99 $ 15.23 Net earnings attributable to common shareholders (3) $ 1,407 $ 570 $ 642 Per common share - basic $ 10.48 $ 4.46 $ 5.30 - diluted $ 10.14 $ 4.31 $ 5.17 Business combinations $ -- $ 2,393 $ -- Capital expenditures, net of dispositions $ 2,506 $ 1,676 $ 1,885 - -----------------------------------------------------------------------------------------------------------------
(1) Restated to conform to current year presentation. (2) Cash flow from operations attributable to common shareholders is a non-GAAP term that represents net earnings attributable to common shareholders adjusted for non-cash items. The Company evaluates its performance and that of its business segments based on net earnings and cash flow from operations. The Company considers cash flow a key measure as it demonstrates the Company's ability and the ability of its business segments to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
($ millions) 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- Net earnings attributable to common shareholders $ 1,407 $ 570 $ 642 Non-cash items: Future tax on dividend on preferred securities (4) (4) (4) Revaluation of preferred securities, net of tax (18) (1) 8 Stock-based compensation expense 200 -- -- Depletion, depreciation and amortization 1,565 1,314 903 Unrealized foreign exchange (gain) loss (320) (35) 64 Loss on sale of United States assets -- -- 24 Deferred petroleum revenue tax (9) 10 -- Future income tax expense 339 400 283 ------------------------------------------------------------------------------------------------------------------- Cash flow from operations attributable to common shareholders $ 3,160 $ 2,254 $ 1,920 ===================================================================================================================
(3) After dividend and revaluation of preferred securities. Cash flow from operations attributable to common shareholders reached record levels in 2003. Cash flow from operations attributable to common shareholders increased 40% to $3,160 million ($23.54 per common share), up from $2,254 million ($17.63 per common share) in 2002 and $1,920 million ($15.83 per common share) in 2001. The increase in cash flow resulted primarily from higher product prices and increased production volumes. In 2003, the Company's average price per barrel of crude oil and NGLs increased 6% to $31.59 from $29.76 in 2002 (2001 - $24.31). The Company's average natural gas price increased 60% to $6.02 per mcf from $3.76 per mcf in 2002 (2001 - $5.16 per mcf). Production volumes increased 9% to 458,814 boe/d from 420,722 boe/d in 2002 (2001- 359,347 boe/d). The increase in production volumes was primarily associated with an active capital expenditure program, the consolidation of working interests in the North Sea, and the impact of a full year of results relating to the acquisition of Rio Alto on July 1, 2002. Net earnings attributable to common shareholders also reached record levels in 2003. Net earnings attributable to common shareholders increased 147% in 2003 to $1,407 million ($10.48 per common share), up from $570 million ($4.46 per common share) in 2002 and $642 million ($5.30 per common share) in 2001. Net earnings attributable to common shareholders in 2003 was impacted by the reduction in the Canadian federal and Alberta provincial corporate income tax rates, the strengthening Canadian dollar, which resulted in increased unrealized foreign exchange gains on the Company's US dollar denominated debt, and the recognition of stock-based compensation expense associated with the Company's Stock Option Plan. [GRAPHIC OMITTED - LINE CHART] [GRAPHIC OMITTED - LINE CHART] CASH FLOW FROM OPERATIONS NET EARNINGS ATTRIBUTABLE TO ATTRIBUTABLE TO COMMON SHAREHOLDERS COMMON SHAREHOLDERS PER SHARE $millions $per share 99 724 99 2.11 00 1,884 00 6.57 01 1,920 01 5.30 02 2,254 02 4.46 03 3,160 03 10.48 [GRAPHIC OMITTED - LINE CHART] [GRAPHIC OMITTED - LINE CHART] NET EARNINGS ATTRIBUTABLE RETURN ON AVERAGE COMMON TO COMMON SHAREHOLDERS SHAREHOLDER'S EQUITY $millions percent 99 220 99 14.5 00 767 00 31.6 01 642 01 18.8 02 570 02 13.8 03 1,407 03 25.7 41 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - --------------------------------------------------------------------------------
OPERATING HIGHLIGHTS 2003 2002 2001 - ----------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl, except daily production) Daily production, before royalties (bbl/d) 242,392 215,335 206,323 Sales price (1) $ 31.59 $ 29.76 $ 24.31 Royalties 2.77 3.16 2.17 Production expense 10.28 8.45 7.64 - ----------------------------------------------------------------------------------------------------------------------------- Netback $ 18.54 $ 18.15 $ 14.50 - ----------------------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/mcf, except daily production) Daily production, before royalties (mmcf/d) 1,299 1,232 918 Sales price (1) $ 6.02 $ 3.76 $ 5.16 Royalties 1.32 0.78 1.25 Production expense 0.60 0.57 0.51 - ----------------------------------------------------------------------------------------------------------------------------- Netback $ 4.10 $ 2.41 $ 3.40 - ----------------------------------------------------------------------------------------------------------------------------- BARREL OF OIL EQUIVALENT ($/boe, except daily production) Daily production, before royalties (boe/d) 458,814 420,722 359,347 Sales price (1) $ 33.75 $ 26.25 $ 27.15 Royalties 5.20 3.91 4.42 Production expense 7.15 5.99 5.69 - ----------------------------------------------------------------------------------------------------------------------------- Netback $ 21.40 $ 16.35 $ 17.04 - -----------------------------------------------------------------------------------------------------------------------------
(1) Including financial instruments and transportation costs.
BUSINESS ENVIRONMENT 2003 2002 2001 - ----------------------------------------------------------------------------------------------------------------------------- WTI benchmark price (US$/bbl) $ 31.02 $ 26.11 $ 25.91 Differential to LLB blend (US$/bbl) $ 8.55 $ 6.50 $ 10.73 Condensate benchmark price (US$/bbl) $ 31.42 $ 26.00 $ 28.12 NYMEX benchmark price (US$/mmbtu) $ 5.44 $ 3.25 $ 4.38 AECO benchmark price (C$/GJ) $ 6.35 $ 3.86 $ 5.92 US/Canadian dollar average exchange rate (US$) 0.71 0.64 0.65 - -----------------------------------------------------------------------------------------------------------------------------
World crude oil prices remained strong throughout 2003 due to concerns over supply relating to the war in Iraq, the strike in Venezuela, the unrest in Nigeria and rising worldwide demand. West Texas Intermediate ("WTI") prices increased 19% to average US$31.02 per bbl, up from US$26.11 per bbl in 2002 (2001 - US$25.91 per bbl). In 2003, the heavy oil differential averaged US$8.55 per bbl, up from US$6.50 per bbl in 2002 (2001 - US$10.73 per bbl). Natural gas prices increased in 2003 due to market forces of supply and demand. AECO natural gas price increased 65% to average $6.35 per GJ in 2003 compared to $3.86 per GJ in 2002 (2001 - $5.92 per GJ). NYMEX natural gas spot price increased 67% to average US$5.44 per mmbtu compared to US$3.25 per mmbtu in 2002 (2001 - US$4.38 per mmbtu). REVENUE PRODUCT PRICES (1) 2003 2002 2001 - -------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl) North America $ 27.77 $ 27.04 $ 21.00 North Sea $ 42.43 $ 39.79 $ 38.66 Offshore West Africa $ 36.47 $ 40.10 $ 33.57 Company average $ 31.59 $ 29.76 $ 24.31 - -------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/mcf) North America $ 6.14 $ 3.78 $ 5.19 North Sea $ 3.03 $ 2.75 $ 2.51 Offshore West Africa $ 4.37 $ 4.82 $ -- Company average $ 6.02 $ 3.76 $ 5.16 - -------------------------------------------------------------------------------------------------------------- PERCENTAGE OF REVENUE (excluding midstream revenue) Crude oil and NGLs 49% 58% 52% Natural gas 51% 42% 48% - --------------------------------------------------------------------------------------------------------------
(1) Including financial instruments and transportation costs. 42 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - --------------------------------------------------------------------------------
ANALYSIS OF CHANGES IN REVENUE - ------------------------------------------------------------------------------------------------------------------------------------ Changes due to CHANGES DUE TO ($ millions) 2001 Volumes Prices Other 2002 VOLUMES PRICES OTHER 2003 - ------------------------------------------------------------------------------------------------------------------------------------ NORTH AMERICA Crude oil and NGLs $ 1,339 $ 23 $ 386 $ -- $ 1,748 $ 52 $ 49 $ -- $ 1,849 Natural gas 1,824 565 (527) -- 1,862 56 1,062 -- 2,980 - ------------------------------------------------------------------------------------------------------------------------------------ 3,163 588 (141) -- 3,610 108 1,111 -- 4,829 - ------------------------------------------------------------------------------------------------------------------------------------ NORTH SEA Crude oil and NGLs 523 37 24 -- 584 261 36 -- 881 Natural gas 11 14 3 -- 28 19 33 -- 80 - ------------------------------------------------------------------------------------------------------------------------------------ 534 51 27 -- 612 280 69 -- 961 - ------------------------------------------------------------------------------------------------------------------------------------ OFFSHORE WEST AFRICA Crude oil and NGLs 42 42 16 -- 100 56 (14) -- 142 Natural gas -- 2 -- -- 2 13 (1) -- 14 - ------------------------------------------------------------------------------------------------------------------------------------ 42 44 16 -- 102 69 (15) -- 156 - ------------------------------------------------------------------------------------------------------------------------------------ SUBTOTAL Crude oil and NGLs 1,904 102 426 -- 2,432 369 71 -- 2,872 Natural gas 1,835 581 (524) -- 1,892 88 1,094 -- 3,074 - ------------------------------------------------------------------------------------------------------------------------------------ 3,739 683 (98) -- 4,324 457 1,165 -- 5,946 MIDSTREAM 27 -- -- 25 52 -- -- 9 61 INTERSEGMENT ELIMINATIONS (1) (9) -- -- (25) (34) -- -- (1) (35) - ------------------------------------------------------------------------------------------------------------------------------------ TOTAL $ 3,757 $ 683 $ (98) $ -- $ 4,342 $ 457 $ 1,165 $ 8 $ 5,972 ====================================================================================================================================
(1) Eliminates internal transportation and electricity charges. Revenue rose 38% to $5,972 million in 2003, up from $4,342 million in 2002 (2001 - - $3,757 million). In 2003, 19% of the Company's crude oil and natural gas revenue was generated outside of North America, up from 16% in 2002 (2001 - 15%). North Sea accounted for 16% of revenue in 2003 and 14% in 2002 (2001 - 14%), and Offshore West Africa accounted for 3% of revenue in 2003 and 2% in 2002 (2001 - 1%). Crude oil and NGLs pricing realized by the Company is directly correlated with fluctuations in world oil pricing and heavy oil differentials. The realized crude oil and NGLs price earned by the Company in 2003 increased 6% to average $31.59 per bbl for the year, up from $29.76 per bbl in 2002 (2001 - $24.31 per bbl). The Company's realized crude oil price was impacted by the increase in world oil prices, the higher heavy oil differential, and the strengthening Canadian dollar (see Sensitivity Analysis). Natural gas prices increased 60% to average $6.02 per mcf, up from $3.76 per mcf in 2002 (2001 - $5.16 per mcf), due to market forces of supply and demand in 2003. Lower demand and higher storage levels in the first half of the year impacted natural gas prices in 2002. The Company uses certain financial instruments to protect against downside commodity prices received on the sale of certain crude oil and natural gas production to ensure adequate resources are available for its capital program. The price realized from the sale of crude oil was reduced by $1.07 per bbl in 2003 compared to $1.46 per bbl in 2002 (2001 - increase of $0.86 per bbl) due to the impact of financial instruments. In addition, the price realized from the sale of natural gas was reduced by $0.19 per mcf in 2003 compared to a reduction of $0.01 per mcf in 2002 (2001 - reduction of $0.29 per mcf) due to the impact of financial instruments. The financial instruments as at December 31, 2003, are summarized in note 10 to the consolidated financial statements. A comparison of the price received for the Company's North America production is as follows: 2003 2002 2001 - -------------------------------------------------------------------------------- Wellhead Price (1) Light crude oil and NGLs (C$/bbl) $ 35.92 $ 32.88 $ 34.73 Pelican Lake crude oil (C$/bbl) $ 26.31 $ 25.92 $ 19.46 Primary heavy crude oil (C$/bbl) $ 24.70 $ 25.40 $ 17.64 Thermal heavy crude oil (C$/bbl) $ 23.85 $ 24.12 $ 15.20 Natural gas (C$/mcf) $ 6.14 $ 3.78 $ 5.19 - -------------------------------------------------------------------------------- (1) Including financial instruments and transportation costs. 43 Annual Report 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- DAILY PRODUCTION, BEFORE ROYALTIES 2003 2002 2001 - -------------------------------------------------------------------------------- CRUDE OIL AND NGLS (bbl/d) North America 174,895 169,675 166,675 North Sea 56,869 38,876 36,252 Offshore West Africa 10,628 6,784 3,396 - -------------------------------------------------------------------------------- Total 242,392 215,335 206,323 - -------------------------------------------------------------------------------- NATURAL GAS (mmcf/d) North America 1,245 1,204 906 North Sea 46 27 12 Offshore West Africa 8 1 -- - -------------------------------------------------------------------------------- Total 1,299 1,232 918 - -------------------------------------------------------------------------------- PRODUCT MIX Light crude oil and NGLs 25% 21% 21% Pelican Lake crude oil 5% 7% 9% Primary heavy crude oil 15% 14% 16% Thermal heavy crude oil 8% 9% 11% Natural gas 47% 49% 43% - -------------------------------------------------------------------------------- The Company's daily crude oil and NGLs production increased 13% or 27,057 bbl/d to average 242,392 bbl/d in 2003, up from 215,335 bbl/d in 2002 (2001 - 206,323 bbl/d). Crude oil and NGLs production in 2003 increased in all segments from the previous year and was in line with production guidance provided. Crude oil and NGLs production in North America for the year ended December 31, 2003 increased 3% or 5,220 bbl/d to average 174,895 bbl/d, up from 169,675 bbl/d in 2002 (2001 - 166,675 bbl/d). The increase in North America production is attributable to heavy oil drilling and recompletion activity in 2003, property acquisitions in its core operating regions in 2002, and the impact of a full year production from the properties acquired in the Rio Alto acquisition. Crude oil production from the Pelican Lake Field declined as a result of the implementation of the water flood program, which required producing wells to be converted to injectors. Crude oil production from the North Sea for the year ended December 31, 2003 increased 46% or 17,993 bbl/d to average 56,869 bbl/d, up from 38,876 bbl/d in 2002 (2001 - 36,252 bbl/d). The increase was a result of drilling activities, which focused on unswept oil reserves within the Ninian, Murchison and Columba Fields, recompletion activities where a number of wells were re-entered to access behind pipe reserves, and the continued consolidation of the Company's working interests in the North Sea. Crude oil production from the North Sea in 2003 was also impacted by two unscheduled turnarounds on the Ninian South Platform. Production from the Ninian South Platform was shut in from late March 2003 to late April 2003 in order to replace critical pipework to significantly increase the reliability and integrity of the Platform. Offshore West Africa crude oil production for the year ended December 31, 2003, increased 57% or 3,844 bbl/d to average 10,628 bbl/d, up from 6,784 bbl/d in 2002 (2001 - 3,396 bbl/d). The increase in crude oil production is due to the commencement of production from the Company's operated Espoir Field, located offshore Cote d'Ivoire, in 2002. In addition, crude oil production increased due to the perforation of the upper zone of the East Espoir structure in the second quarter of 2003, and the completion of the fourth water injection well and two additional producing wells in 2003. The Company continues to look for opportunities to expand its heavy oil markets. In particular, the Company is testing a 50/50 blend of bitumen and synthetic crude oil called "Synbit". Synbit has similar properties to medium sour crude oil and is expected to decrease the demand for supplies of condensate currently blended with bitumen. The Company is currently marketing 34,000 bbl/d of Synbit to refiners located in the US Midwest and plans to expand this effort throughout 2004 to build a solid new market for both heavy and synthetic crude oil. [GRAPHIC OMITTED - LINE CHART] [GRAPHIC OMITTED - LINE CHART] NATURAL GAS PRODUCTION CRUDE OIL AND NGLs BEFORE ROYALTIES PRODUCTION BEFORE ROYALTIES mmcf/d mbbl/d 99 721 99 87 00 794 00 174 01 918 01 206 02 1,232 02 215 03 1,299 03 242 44 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- Natural gas continues to represent the Company's largest product offering, accounting for 47% of the Company's total production in 2003 compared to 49% of total production in 2002 (2001 - 43%). Natural gas production increased 5% or 67 mmcf/d to average 1,299 mmcf/d, up from 1,232 mmcf/d in 2002 (2001 - 918 mmcf/d). Annual natural gas production was in line with the production guidance provided. North America accounts for 96% of the Company's natural gas production in 2003, down from 98% in 2002 (2001 - 99%). Overall, natural gas production in North America increased 3% or 41 mmcf/d to average 1,245 mmcf/d, up from 1,204 mmcf/d in 2002 (2001 - 906 mmcf/d). The increase in natural gas production was due to ongoing drilling activities and the acquisition of Rio Alto on July 1, 2002. Natural gas production in 2003 was impacted by steep production declines from the Ladyfern Field. Ladyfern natural gas production decreased 67% or 112 mmcf/d to average 56 mmcf/d, down from 168 mmcf/d in 2002 (2001 - 40 mmcf/d). Production of natural gas was also impacted by the shut in of approximately 11 mmcf/d of the Company's natural gas production in the Athabasca Wabiskaw-McMurray oilsands area pursuant to the decision of the Alberta Energy and Utilities Board ("EUB") effective September 1, 2003. North Sea natural gas production increased 70% or 19 mmcf/d to average 46 mmcf/d, up from 27 mmcf/d in 2002 (2001 - 12 mmcf/d). The increase was due to the acquisition of additional interests in the Banff Field. Natural gas production from the North Sea in 2004 is expected to decrease due to the implementation of the natural gas re-injection program on the Banff Field to maximize recovery from the reservoir. Natural gas production in Offshore West Africa increased 7 mmcf/d to average 8 mmcf/d, up from 1 mmcf/d in 2002 (2001 - nil). Production increased due to the completion of the natural gas pipeline in the Espoir Field in the third quarter of 2002. Natural gas production also increased from the previous year due to the perforation of the upper zone of the East Espoir structure in the second quarter of 2003 and the drilling of additional production and injection wells in 2003. ROYALTIES 2003 2002 2001 - ------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl) North America $ 3.79 $ 3.42 $ 2.22 North Sea $ (0.03) $ 2.30 $ 2.10 Offshore West Africa $ 1.08 $ 1.35 $ 0.93 Company average $ 2.77 $ 3.16 $ 2.17 - ------------------------------------------------------------------------------- NATURAL GAS ($/mcf) North America $ 1.38 $ 0.80 $ 1.26 Offshore West Africa $ 0.13 $ 0.15 $ -- Company average $ 1.32 $ 0.78 $ 1.25 - ------------------------------------------------------------------------------- COMPANY AVERAGE ($/boe) $ 5.20 $ 3.91 $ 4.42 - ------------------------------------------------------------------------------- PERCENTAGE OF REVENUE (1)(2) Crude oil and NGLs 9% 10% 9% Natural gas 21% 21% 23% - ------------------------------------------------------------------------------- (1) Excludes the impact of financial instruments. (2) Transportation costs netted against revenue. Crude oil and NGLs royalties in North America increased to $3.79 per bbl, up from $3.42 per bbl in 2002 (2001 - $2.22 per bbl), due to certain primary and thermal heavy oil projects reaching payout and becoming subject to higher government royalty rates. The majority of the Company's oil sands projects continue to benefit from reduced royalty rates as a result of the Alberta program to promote development of oil sands resources, which provides a reduced royalty rate until an oil sands project recovers its capital costs. Effective January 1, 2003, government royalties in the North Sea were eliminated. In 2003, the Company received a refund of royalties related to the Ninian Field. As a result North Sea crude oil royalties recovered $0.03 per bbl as opposed to an expense of $2.30 per bbl in 2002 (2001 - $2.10 per bbl). Offshore West Africa crude oil royalties decreased to $1.08 per bbl, down from $1.35 per bbl in 2002 (2001 - $0.93 per bbl) due to fluctuations in realized crude oil prices. Natural gas royalties for the Company increased to $1.32 per mcf, up from $0.78 per mcf in 2002 (2001 - $1.25 per mcf), due to the overall increase in natural gas prices. North America natural gas royalties have a strong correlation to changes in natural gas prices. 45 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- PRODUCTION EXPENSE 2003 2002 2001 - -------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl) North America $ 9.14 $ 6.73 $ 7.05 North Sea $ 14.07 $ 15.06 $ 9.00 Offshore West Africa $ 8.68 $ 13.63 $ 21.77 Company average $ 10.28 $ 8.45 $ 7.64 - -------------------------------------------------------------------------------- NATURAL GAS ($/mcf) North America $ 0.57 $ 0.55 $ 0.50 North Sea $ 1.33 $ 1.53 $ 0.94 Offshore West Africa $ 1.39 $ 1.81 $ -- Company average $ 0.60 $ 0.57 $ 0.51 - -------------------------------------------------------------------------------- COMPANY AVERAGE ($/boe) $ 7.15 $ 5.99 $ 5.69 - -------------------------------------------------------------------------------- Production expense increased to $7.15 per boe, up from $5.99 per boe in 2002 (2001 - $5.69 per boe). The increase was primarily related to higher costs associated with operations in North America. North America crude oil and NGLs production expense increased to $9.14 per bbl from $6.73 per bbl in 2002 (2001 - $7.05 per bbl). The increase was mainly a result of higher repair and maintenance costs incurred with regard to property acquisitions as well as costs associated with the conversion and implementation of the Pelican Lake water flood pilots. The increase was also impacted by the cost of fuel gas used in the generation of steam in the Company's thermal oil operations. North Sea crude oil production expense decreased in 2003 to $14.07 per bbl from $15.06 per bbl in 2002 (2001 - $9.00 per bbl), due to the timing of maintenance work and changes in production volumes on a relatively fixed cost base. Production expense in the North Sea was higher than normal in 2002 due to costs associated with rectifying a natural gas pipeline blockage in the Kyle Field. Offshore West Africa crude oil production expense decreased to $8.68 per bbl from $13.63 per bbl in 2002 (2001 - $21.77 per bbl) resulting from production increases in the Espoir Field. The Espoir Field commenced operations in the first quarter of 2002. Production expenses are largely fixed in nature and therefore decreased on a per barrel basis as production increased. The higher production expense in 2001 was related to costs associated with the Kiame Field, located offshore Angola, which ceased operations early in 2002. Natural gas production expense for the year 2003 increased to $0.60 per mcf, up from $0.57 per mcf in 2002 (2001 - $0.51 per mcf). North America natural gas production expense increased to $0.57 per mcf, up from $0.55 per mcf in 2002 (2001 - $0.50 per mcf), as a result of a general increase in service costs associated with increased industry activity. MIDSTREAM ($ millions) 2003 2002 2001 - -------------------------------------------------------------------------------- Revenue $ 61 $ 52 $ 27 Operating costs 15 14 11 - -------------------------------------------------------------------------------- Operating cash flow 46 38 16 Depreciation 7 8 4 - -------------------------------------------------------------------------------- Segment earnings before taxes $ 39 $ 30 $ 12 - -------------------------------------------------------------------------------- The Company's midstream assets consist of three crude oil pipeline systems and an 84-megawatt cogeneration plant at Primrose where the Company has a 50% working interest. Approximately 85% of the Company's heavy oil production was transported to international liquid pipelines via the 100% owned and operated ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15% owned Cold Lake Pipeline, which commenced operations in late 2001. The midstream pipeline assets allow the Company to transport its own production volumes at reduced costs compared to other transportation alternatives as well as earn third party revenue. This transportation control enhances the Company's ability to control the full range of costs associated with the development and marketing of its heavy oil. Revenue from the midstream assets increased 17% to $61 million, up from $52 million in 2002 (2001 - $27 million). The increase in revenue, operating cashflow and segment earnings before taxes was due to higher electricity prices received in the first quarter of 2003 and increased revenue generated as a result of the expansion of the ECHO Pipeline. The expansion of the ECHO Pipeline was completed in October 2003 and increased capacity to 72 mbbl/d from 58 mbbl/d. 46 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- The Cold Lake Pipeline Limited Partnership, in which the Company has a 15% working interest, will be investing $16 million in 2004 to construct new facilities to allow shipment of up to 60,000 bbl/d of Synbit product. The new Synbit product will include light synthetic oil as a blending component to dilute the heavy, tar-like Cold Lake bitumen. The Synbit project will involve construction of two 80,000 barrel storage tanks, pumping facilities and metering equipment on the Cold Lake system. Regulatory approvals have been obtained and construction activity is currently underway. DEPLETION, DEPRECIATION AND AMORTIZATION (1) ($ millions, except per boe amounts) 2003 2002 2001 - -------------------------------------------------------------------------------- North America $1,248 $1,033 $746 North Sea 268 193 129 Offshore West Africa 42 80 24 Expense $1,558 $1,306 $899 - -------------------------------------------------------------------------------- $/boe $9.30 $8.51 $6.86 - -------------------------------------------------------------------------------- (1) DD&A excludes depreciation on midstream assets. Depletion, depreciation and amortization ("DD&A") increased in total and per boe to $1,558 million or $9.30 per boe from $1,306 million or $8.51 per boe in 2002 (2001 - $899 million or $6.86 per boe). These increases were due to the higher finding and development costs associated with natural gas exploration in North America, the allocation of the acquisition costs associated with Rio Alto, and future abandonment costs associated with the acquisition of additional interests in the North Sea. In addition, DD&A included the write-off of $12 million of costs associated with the Company's exploration activity in offshore France in 2003. In 2002, DD&A included the write-off of $51 million as a result of the Company's decision to exit from its interests in Block 19, Angola, and from the Aje Field, Nigeria. ADMINISTRATION EXPENSE ($ millions, except per boe amounts) 2003 2002 2001 - -------------------------------------------------------------------------------- Gross cost $ 262 $ 147 $ 110 $/boe $ 1.57 $ 0.96 $ 0.84 Net expense $ 87 $ 61 $ 38 $/boe $ 0.52 $ 0.40 $ 0.29 Gross administration expense increased to $1.57 per boe from $0.96 per boe in 2002 (2001 - $0.84 per boe) mainly due to higher staffing levels associated with the Company's expanding asset base and costs associated with the Horizon Project. Gross administration expense also increased as a result of higher costs related to the assumption of operatorship of certain fields in the North Sea. Net administration expense, after operator recoveries and capitalized overhead relating to exploration and development in the North Sea and Offshore West Africa as well as the Horizon Project, increased to $0.52 per boe in 2003 from $0.40 per boe in 2002 (2001 - $0.29 per boe). STOCK-BASED COMPENSATION ($ millions, except per boe amounts) 2003 2002 2001 - -------------------------------------------------------------------------------- Stock-based compensation expense $ 200 $ -- $ -- $/boe $ 1.20 $ -- $ -- - -------------------------------------------------------------------------------- In June 2003, the Board of Directors approved an amendment to the Company's Stock Option Plan (the "Option Plan") that provides current employees, officers and directors (the "option holders") with the right to elect to receive common shares or a direct cash payment in exchange for options surrendered. Amendments to the Option Plan balance the need for a long-term compensation program to retain employees with reducing the impact of dilution on current shareholders and the reporting of the expense associated with stock options. Transparency of the cost of the Option Plan is increased since changes in the intrinsic value of outstanding stock options are expensed. The cash payment feature provides option holders with substantially the same benefits and allows them to realize the value of their options through a simplified administration process. As a result of the amendment to the Option Plan, the Company has recorded a liability at December 31, 2003, of $171 million for expected cash settlements based on the intrinsic value of the outstanding stock options (the difference between the exercise price of the stock options and the market price of the Company's common shares). Compensation expense for 2003 is $200 million ($136 million net of tax). The liability is revalued quarterly to reflect changes in the market price of the Company's common shares and the net change is recognized in net earnings. In 2003, the Company paid $31 million in cash settlements for stock options surrendered. INTEREST EXPENSE ($ millions, except per boe amounts) 2003 2002 2001 - -------------------------------------------------------------------------------- Interest expense $ 157 $ 159 $ 138 $/boe $ 0.94 $ 1.03 $ 1.05 Average effective interest rate 4.7% 4.5% 5.4% - -------------------------------------------------------------------------------- 47 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- Interest expense decreased to $157 million in 2003 from $159 million in 2002 (2001 - $138 million) due to lower average outstanding debt levels as the Company used excess cash flow generated to repay $740 million of long-term debt in 2003. The impact of the lower debt levels was partially offset by the higher average effective interest rate of 4.7%, up from 4.5% in 2002 (2001 - 5.4%). In addition, the strengthening Canadian dollar reduced the Canadian equivalent interest expense on the Company's US dollar denominated debt. Interest expense decreased to $0.94 per boe in 2003 compared to $1.03 per boe in 2002 (2001 - $1.05 per boe) as a result of the lower average outstanding debt levels and higher production. The Company continues to benefit from the lower short-term interest rates as its fixed-rate debt accounts for only 38% of total debt outstanding after interest rates swaps (see note 10 to the consolidated financial statements) as at December 31, 2003 (2002 - 40%, 2001 - 21%). FOREIGN EXCHANGE ($ millions) 2003 2002 2001 - -------------------------------------------------------------------------------- Realized foreign exchange loss (gain) $ 8 $ 4 $ (1) Unrealized foreign exchange (gain) loss (320) (35) 64 - -------------------------------------------------------------------------------- Total $(312) $ (31) $ 63 - -------------------------------------------------------------------------------- The Canadian dollar increased to US$0.77 at December 31, 2003, compared to US$0.63 at January 1, 2003, resulting in an unrealized foreign exchange gain on the Company's US dollar denominated debt. The Canadian dollar averaged US$0.71 in 2003, up from US$0.64 in 2002 (2001 - US$0.65). The majority of the Company's borrowings are denominated in US dollars. At December 31, 2003, the Company's US dollar denominated debt amounted to US$1,965 million compared to US$1,968 million in 2002 (2001 - US$899 million). US dollar denominated debt represented 91% of total debt outstanding at December 31, 2003 (2002 - 76%, 2001 - 53%). Due to the higher proportion of US dollar denominated debt outstanding, the Company's net earnings are more sensitive to fluctuations in the Canadian dollar. In order to mitigate a portion of the volatility associated with the Canadian dollar, the Company has designated certain US dollar denominated debt as a hedge against its net investment in US dollar based self-sustaining foreign operations. Accordingly, translation gains and losses on this US dollar denominated debt are included in the foreign currency translation adjustment in shareholders' equity in the consolidated balance sheets. The Company's realized product prices are sensitive to currency exchange rates. Recent increases in the value of the Canadian dollar in relation to the US dollar had a negative impact on the Company's commodity price realized (see Sensitivity Analysis). TAXES ($ millions, except income tax rates) 2003 2002 2001 - -------------------------------------------------------------------------------- Taxes other than income tax Current $ 116 $ 53 $ 69 Deferred (9) 10 -- - -------------------------------------------------------------------------------- Total $ 107 63 69 - -------------------------------------------------------------------------------- Current income tax North America - Current income tax $ 43 $ -- $ -- North America - Large Corporations Tax 16 21 15 North Sea 23 (19) 62 Offshore West Africa 10 6 -- - -------------------------------------------------------------------------------- Total $ 92 $ 8 $ 77 - -------------------------------------------------------------------------------- Future income tax $ 339 $ 400 $ 283 - -------------------------------------------------------------------------------- Effective income tax rate 23.6% 41.6% 35.4% - -------------------------------------------------------------------------------- Taxes other than income tax consist of current and deferred petroleum revenue tax ("PRT"), other international taxes and provincial capital taxes and surcharges. PRT is charged on certain fields in the North Sea at the rate of 50% of net operating income after certain deductions including abandonment expenditures. Taxes other than income tax increased to $107 million or $0.64 per boe in 2003, up from $63 million or $0.41 per boe in 2002 (2001 - $69 million or $0.53 per boe). The increase in taxes other than income tax was mainly due to the higher netback earned in the North Sea as a result of higher crude oil prices and higher production levels. North Sea PRT accounts for $97 million or $0.58 per boe in 2003 compared to $51 million or $0.33 per boe in 2002 (2001 - $59 million or $0.45 per boe). Current income tax in the North Sea increased to $23 million or $0.14 per boe, up from a recovery of $19 million or $0.13 per boe in 2002 (2001 - expense of $62 million or $0.47 per boe). The increase in the current income tax expense was a result of increased production and higher crude oil prices. The North Sea current income tax was also impacted by changes in the tax rules in the North Sea. In 2002, a supplementary charge of 10% on 48 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- profits from UK North Sea crude oil and natural gas production was introduced. The North Sea supplementary charge, which took effect April 17, 2002, is in addition to the corporate income tax rate of 30% and excludes any deduction for financing costs. In addition, the first year capital allowance rate for plant and machinery expenditures was increased to 100% from the previous rate of 25%. Taxable income from the conventional crude oil and natural gas business in Canada is generated by partnerships and the related income taxes will be payable in the following year. Current income taxes have been provided on the basis of the corporate structure and available income tax deductions. No current income tax provision was required for North America in 2002 and 2001. The Company is liable for the payment of Federal LCT. LCT decreased to $16 million or $0.09 per boe from $21 million or $0.14 per boe (2001 - $15 million or $0.11 per boe) as a result of the Company being taxable and paying the Federal corporate surtax. In 2003, the Canadian Federal Government passed legislation to eliminate the federal Large Corporations Tax ("LCT") over a five-year period starting January 1, 2004. The LCT was levied at a rate of 0.225% of the Company's taxable capital employed in Canada in 2003 (2004 - 0.2%). The Federal Government also passed legislation to reduce the corporate income tax rate on income from resource activities from 28% to 21% over a five-year period starting January 1, 2003, bringing the resource industry in line with the general corporate income tax rate. As part of the corporate income tax rate reduction, the legislation also provides for the elimination of the existing 25% resource allowance and the introduction of a deduction for actual provincial and other crown royalties paid. As a result of these changes, the future income tax liability in North America was decreased by $247 million in 2003. In 2003 the North America future income tax liability was also reduced by $31 million as a result of a reduction in the Alberta corporate income tax rate (2002 - $21 million, 2001 - $63 million). The Company's future income tax provision for 2003 decreased to $339 million ($2.02 per boe), down from $400 million ($2.61 per boe) in 2002 (2001 - $283 million or $2.02 per boe) due to changes noted above. In 2002, the future income tax liability in the North Sea was increased by $34 million as a result of the introduction in the UK of a 10% supplementary charge on profits from North Sea crude oil and natural gas production. The increase in the North Sea future income tax liability was partially offset by a $21 million decrease in the North America future income tax liability as a result of a reduction in the Alberta provincial corporate income tax rate in the second quarter of 2002. Future income taxes also increased in 2002 because of the increased capital allowance rates in the North Sea, resulting in a lower current tax expense and a higher future income tax expense. The Company's effective tax rate decreased to 23.6% for 2003 from 41.6% for 2002 (2001 - 35.4%) as a result of the reductions in the Federal and Alberta corporate income tax rates in 2003. It is anticipated that, based on the current availability of approximately $4 billion of tax pools in Canada at the end of 2003 and current commodity strip prices, the Company will be cash taxable in Canada in 2004 in the amount of $100 million to $175 million.
LIQUIDITY AND CAPITAL RESOURCES ($ millions, except ratios) 2003 2002 2001 - -------------------------------------------------------------------------------------------------------- Working capital deficit (1) $ 505 $ 14 $ 6 Long-term debt 2,645 4,074 2,669 - -------------------------------------------------------------------------------------------------------- Net debt $3,150 $4,088 $2,675 - -------------------------------------------------------------------------------------------------------- Shareholders' equity Preferred securities $ 103 $ 126 $ 127 Share capital 2,353 2,304 1,698 Retained earnings 3,644 2,414 1,908 Foreign currency translation adjustment 17 24 73 - -------------------------------------------------------------------------------------------------------- Total $6,117 $4,868 $3,806 - -------------------------------------------------------------------------------------------------------- Debt to cash flow (1) 0.9X 1.8x 1.4x Debt to EBITDA (1)(2)(3) 0.8X 1.6x 1.3x Debt to book capitalization (1) 31.6% 45.6% 41.2% Debt to market capitalization (1) 24.2% 38.9% 34.9% After tax return on average common shareholders' equity (2) 25.7% 13.8% 18.8% After tax return on average capital employed (2) 16.7% 8.9% 12.0% ========================================================================================================
(1) Includes current portion of long-term debt. (2) Based on trailing 12-month activity. (3) Earnings before interest, taxes, depletion, depreciation and amortization. The Company recognizes the need for a strong financial position in order to withstand volatile crude oil and natural gas commodity prices and the operational risks inherent in the crude oil and natural gas business environment. 49 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- LONG-TERM DEBT Long-term debt including current portion at December 31, 2003, decreased $1,269 million from the prior year. The decrease resulted in a debt to EBITDA ratio of 0.8x and a debt to book capitalization of 31.6% compared to a debt to EBITDA ratio of 1.6x and a debt to book capitalization of 45.6% in 2002. These ratios are currently below the Company's guidelines for balance sheet management of debt to EBITDA of 1.5x to 2.0x and debt to book capitalization of 40% to 45%. At December 31, 2003, the Company had: o Approximately $1.6 billion of available unused bank credit facilities; o A fixed / floating interest rate mix of 38% / 62%; o An average cost of borrowing of approximately 4.7%; o 91% of borrowings denominated in US dollars; and o 91% of total long-term debt as non-bank-based borrowing with an average maturity of 14.6 years. In 2003, $740 million of long-term debt was repaid. Long-term debt was also reduced by an additional $529 million as a result of foreign exchange gains on US dollar denominated debt. Higher than budgeted prices received for the Company's products during 2003 resulted in increased cash flow over the budget established in late 2002. Early in 2003, the Company decided to allocate a minimum of 50% of its cash flow surplus toward debt repayment. The remaining excess was directed to the Company's authorized share buy-back program and additional expenditures on conventional crude oil and natural gas opportunities. The largest portion of the additional capital expenditures took place in the fourth quarter of 2003 and accordingly did not add materially to the Company's 2003 average production volumes. In May 2003, the Company filed a short form prospectus that allows for the issue of up to US$2 billion of debt securities in the United States until June 2005. If issued, these securities will bear interest as determined at the date of issuance. In addition, the Company maintains a shelf prospectus in Canada for the offering of up to $1 billion of medium-term notes in Canada. If issued, these securities will bear interest as determined at the date of issuance. Future offerings under the shelf prospectuses will provide flexibility to the Company's debt investment base, extend maturities and provide balance in the fixed to floating interest rate mix. In May 2003, the Company prepaid the US$50 million, 6.50% senior unsecured notes due May 1, 2008. The final principal repayment on the 6.95% senior unsecured notes was made September 30, 2003. The ratings of the Company's debt securities and its relationships with principal banks are extremely important to the Company as it continues to expand and grow. Hence, the Company's management will continually undertake to maintain a strong balance sheet and financial position. The Company's debt securities are rated "Baa1" by Moody's Investor Services Inc., "BBB+" by Standard & Poors Corporation and "BBB(high)" by Dominion Bond Rating Services Limited. As at December 31, 2003, the Company had unsecured bank credit facilities of $1,925 million compared to $2,275 million at the close of 2002 (2001 - $1,840 million). During 2003, the Company repaid and cancelled a $500 million acquisition term credit facility. With respect to the Horizon Project, financing of the first phase of development will be guided by the competing principles of retaining as much direct ownership interest as possible while maintaining current strong debt ratings and not issuing additional equity in common shares. The Company is also investigating the use of long-term commodity hedges in order to reduce cash flow risks during the construction phase. The Company could also look to offload capital commitments through the acceptance of complementary business partners, or potentially, project joint venture partners. Recent commodity price increases have significantly strengthened the balance sheet of the Company, thereby placing it in a better position to achieve all three of its guiding principles. SHARE CAPITAL The Company is authorized to issue an unlimited number of common shares. As at December 31, 2003 and 2002, there were 134 million common shares outstanding. In addition, the Company is also authorized to issue 200,000 Class 1 preferred shares. There were no preferred shares outstanding during these periods. During 2003, the Company issued 2,690 thousand common shares from the exercise of stock options for proceeds of $89 million. In addition, 2,735 thousand common shares were purchased for cancellation under the Normal Course Issuer Bid for a total cost of $144 million, resulting in 45 thousand fewer outstanding common shares than at the beginning of the year. In 2002, the Company issued 10 million common shares at an attributed value of $522 million as part of the consideration to acquire Rio Alto. A further 2,523 thousand common shares were issued from the exercise of stock options throughout 2002 for proceeds of $82 million. The Company issued 60,000 flow-through common shares to a Director of the Company at a price of $39.00 per common share, for total proceeds of $2 million net of tax. The value of the flow-through common shares was determined based on the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the allotment. 50 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- In January 2004, the Company renewed its Normal Course Issuer Bid allowing it to purchase up to 6,690,385 common shares or 5% of the Company's outstanding common shares on the date of announcement, during the 12-month period beginning January 24, 2004, and ending January 23, 2005. As at February 19, 2004, the Company has not purchased any additional shares under the renewed Normal Course Issuer Bid. The Company's Board of Directors has approved an increase in the annual dividend paid by the Company to $0.80 per common share in 2004, up from the previous level of $0.60 per common share. The 33% increase recognizes the stability of the Company's increased cash flow and provides a further return to shareholders. This is the fourth consecutive year in which the Company has paid dividends and the third consecutive year of an increase in the distribution paid to its shareholders. The increased dividend will become effective with the quarterly payment of $0.20 per common share to be paid on April 1, 2004. The Company declared dividends on common shares in the amount of $81 million or $0.60 per common share during the year ended December 31, 2003, up from $64 million or $0.50 per common share in 2002 (2001 - $49 million, $0.40 per common share). In order to increase the liquidity of its common shares, the Board of Directors will recommend to its shareholders to subdivide the Company's common shares on a two for one basis, which will result in an increase in the Company's total outstanding common shares to approximately 268 million common shares. This recommendation will be voted on by the shareholders at the Annual and Special Meeting of Shareholders to be held on May 6, 2004. As at February 19, 2004, the Company has 134,063,267 common shares outstanding. OFF BALANCE SHEET ARRANGEMENTS AND FINANCIAL INSTRUMENTS The Company has operating leases in place on a variety of equipment. These operating leases require periodic lease payments, which are recorded as production expenses. The Company also utilizes various financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for trading or other speculative purposes. The Company enters into commodity price contracts to hedge anticipated sales of crude oil and natural gas production in order to protect cash flow for capital expenditure programs. Gains or losses on these contracts are included in crude oil and natural gas revenue at the time of sale of the related product. Foreign exchange translation gains and losses on foreign currency denominated financial instruments used to hedge future US dollar denominated crude oil and natural gas sales are recognized in revenue at the time of sale of the related product. The Company inherited a foreign currency swap agreement from Rio Alto that hedges a foreign currency denominated long-term debt instrument through an offsetting forward exchange contract. The foreign exchange translation gains and losses on the financial instrument are used to offset the respective translation gains and losses recognized on the long-term debt. The Company enters into interest rate swap agreements to manage its fixed to floating interest rate mix on long-term debt. The interest rate swap agreements require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. Gains or losses on these financial instruments are included in interest expense when realized. The related amount receivable from or payable to counterparties is included as an adjustment to accrued interest in the consolidated balance sheets. Realized gains and losses on the termination of financial instruments that have been accounted for as hedges are deferred under non-current assets or liabilities on the consolidated balance sheets and recognized in net earnings in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized gain or loss is recognized in net earnings. The fair value of these financial instruments is disclosed in note 10 to the consolidated financial statements. COMMITMENTS The Company has various commitments primarily related to debt, operating leases and demand charges on firm transportation agreements. The following table summarizes the Company's commitments as at December 31, 2003.
($ millions) 2004 2005 2006 2007 2008 Thereafter - ----------------------------------------------------------------------------------------------------------------------------- Natural gas transportation $ 180 $ 169 $ 143 $ 103 $ 77 $ 194 Crude oil transportation and pipeline $ 15 $ 13 $ 13 $ 15 $ 13 $ 167 Offshore equipment operating lease $ 169 $ 129 $ 75 $ 75 $ 75 $ 367 Electricity $ 28 $ 27 $ 27 $ -- $ -- $ -- Office lease $ 20 $ 20 $ 19 $ 17 $ 16 $ 50 Processing $ 6 $ 5 $ 2 $ -- $ -- $ -- Preferred securities $ -- $ -- $ -- $ -- $ -- $ 103 Long-term debt $ 184 $ 194 $ -- $ 165 $ 40 $1,978 - -----------------------------------------------------------------------------------------------------------------------------
51 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - --------------------------------------------------------------------------------
CAPITAL EXPENDITURES ($ millions) 2003 2002 2001 - ---------------------------------------------------------------------------------------------------------------- BUSINESS COMBINATIONS $ -- $2,393 $ -- - ---------------------------------------------------------------------------------------------------------------- EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT Net property acquisitions $ 336 $ 440 $ 519 Land acquisition and retention 154 114 101 Seismic evaluations 77 63 95 Well drilling, completion and equipping 1,194 626 635 Pipeline and production facilities 522 292 395 - ---------------------------------------------------------------------------------------------------------------- TOTAL NET RESERVE REPLACEMENT EXPENDITURES 2,283 1,535 1,745 Horizon Oil Sands Project 152 68 27 Midstream 11 20 97 Abandonments 40 43 10 Head office 20 10 6 - ---------------------------------------------------------------------------------------------------------------- TOTAL NET CAPITAL EXPENDITURES $2,506 $1,676 $1,885 - ---------------------------------------------------------------------------------------------------------------- BY SEGMENT (excluding business combinations) North America $1,815 $1,065 $1,459 North Sea 342 333 98 Offshore West Africa 186 190 204 Horizon Project 152 68 27 Midstream 11 20 97 - ---------------------------------------------------------------------------------------------------------------- Total $2,506 $1,676 $1,885 - ----------------------------------------------------------------------------------------------------------------
The Company's strategy is focused on continuing to build a diversified asset base that is balanced between products, namely natural gas, light oil, Pelican Lake oil, primary heavy oil and thermal heavy oil. Capital expenditures were $2,506 million in 2003 compared to $1,676 million in 2002, excluding the acquisition of Rio Alto (2001 - $1,885 million). North America accounted for 79% of total capital expenditures, up from 69% in 2002 (2001 - 84%). In 2003, the Company's drilling activity increased 199% with the drilling of 1,353 net wells (excluding stratigraphic test/service wells), up from 453 net wells drilled in 2002 (2001 - 739 net wells). The Company drilled 777 net natural gas wells, up 380% from the 162 net wells in 2002 (2001 - 476 net wells) and 458 net crude oil wells, up 73% from the 264 net wells in 2002 (2001 - 231 net wells). In addition, during 2003 the Company drilled 440 net stratigraphic test/service wells on the oil sands leases in the Horizon Project and in North Alberta. North America 2003 drilling was focused in the Company's heavy crude oil areas of North Alberta (315 net wells), its shallow natural gas area in South Alberta (417 net wells) and its natural gas area in Northwest Alberta (98 net wells). North America capital expenditures also included the expansion of the Company's Primrose properties, where 41 wells were drilled in 2003. Steaming commenced in early 2004 and production from these wells is expected in mid-2004. North America capital expenditures include the acquisition of the West Stoddart natural gas plant. The West Stoddart natural gas plant is located 50 kilometres northwest of Fort St. John, British Columbia and has a processing capacity of 120 mmcf/d. Capital expenditures also included work on the Horizon Project, where the DBM was completed. The Company also completed construction work on the access road and three bridges. Work on the EDS, the third and final stage of engineering work, has commenced and is expected to be completed by mid-2004. The Alberta Energy and Utilities Board and Alberta Environment, in co-operation with other provincial and federal regulatory agencies, have deemed the application for the Horizon Project as being complete. In 2003, North Sea capital expenditures included the drilling of 18 wells focusing on targeting reserves stranded against faults within the Ninian and Murchison Fields. The Company further consolidated its ownership interests to 87.6% in the Banff Field, located in the Central North Sea, by acquiring an additional 31.7% working interest and assuming operatorship. In addition, the Company was the successful bidder on six new exploration licenses at the UK Government's 21st Seaward Licensing Round. These blocks provide for additional exploration lands adjacent to the Ninian hub in the northern North Sea. In 2003, a satellite pool was drilled off the Murchison platform but encountered no hydrocarbons and an unsuccessful exploration well was drilled offshore France. 52 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- Offshore West Africa capital expenditures included the continued development of the Espoir Field located offshore Cote d'Ivoire with the perforation of the upper zone of the East Espoir structure during the second quarter of 2003. Also in the second quarter of 2003, a successful well was drilled in the Acajou satellite pool. Development of the Baobab Field continues with four major contracts being awarded in 2003 for the drilling; supply of subsea Xmas trees, manifolds, flowlines, controls and associated equipment; supply of pipelines, risers and installation of all of the subsea equipment; and the supply and operation of a floating production, storage and offtake vessel. The drilling of the water injection and production wells commenced in the fourth quarter of 2003 and production from the Baobab Field is expected to commence in mid-2005. Construction of the floating production, storage and offtake vessel is currently underway. In 2003, the first of several potential exploration targets located on Block 16, offshore Angola was drilled. The well, Zenza-1, in which the Company has a 50% working interest, was drilled for a total cost of US$17 million, and although the well encountered reservoir quality sands and shows of hydrocarbons, it was not in sufficient amounts to be commercial. Accordingly, the well has been plugged and abandoned. The results of the well will be integrated into the geological model for Block 16 and a second exploratory well will be drilled in 2005. ENVIRONMENT The Company's environmental management plan and operating guidelines focus on minimizing the impact of field operations while meeting regulatory requirements and corporate standards. The Company, as part of this plan, has implemented a proactive program that includes: o An annual internal environmental compliance audit and inspection program of our operating facilities; o An aggressive suspended well inspection program to support future development or eventual abandonment; o Appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; o An effective surface reclamation program; o A progressive due diligence program related to groundwater monitoring; o A rigorous program related to preventing and reclaiming spill sites; o A solution gas reduction and conservation program; and o A program to replace all fresh water for steaming with brackish water. The Company has also established stringent operating standards in four areas: o Using water-based, environmentally friendly drilling muds whenever possible; o Implementing cost effective ways of reducing greenhouse natural gas emissions per unit of production; o Exercising care with respect to all waste produced through effective waste management plans; and o Minimizing produced water volumes onshore and offshore through cost-effective measures. In 2003, the Company's capital expenditures included $40 million of abandonment expenditures, down from $43 million in 2002 (2001 - $10 million). ESTIMATED FUTURE SITE RESTORATION LIABILITY ($ millions) 2003 2002 - -------------------------------------------------------------------------------- North America $ 1,491 $ 1,206 North Sea 764 745 Offshore West Africa 26 35 - -------------------------------------------------------------------------------- 2,281 1,986 North Sea PRT recovery (331) (305) - -------------------------------------------------------------------------------- $ 1,950 $ 1,681 - -------------------------------------------------------------------------------- The estimate of the future site restoration liability is based on estimates of future costs to abandon and restore the wells, production facilities and offshore production platforms. There are numerous factors that affect these costs including such things as the number of wells drilled, well depth and the specific environmental legislation. The estimated costs are based on engineering estimates using current costs and technology in accordance with present legislation and industry practice. It is important to note that the future abandonment costs to be incurred by the Company in the North Sea will result in an estimated recovery of PRT of $331 million (2002 - $305 million), as abandonment costs are an allowable deduction in determining PRT and may be carried back to reclaim PRT previously paid. The PRT recovery reduces the net abandonment liability of the Company to $1,950 million (2002 - $1,681 million). The Company's strategy in the North Sea consists of developing commercial hubs around its core operated properties with the goal of increasing production, lowering costs and extending the economic lives of its production facilities, thereby delaying the eventual abandonment dates. 53 ANNUAL REPORT - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- KYOTO PROTOCOL In December 2002, the Canadian Federal Government ratified the Kyoto Protocol ("Kyoto"). The Company continues to work with departments of the Federal and Provincial governments as legislation and regulatory mechanisms to address the issue of climate change develop. There continues to be uncertainty about the ratification of Kyoto, as certain countries have not yet committed to this treaty. The Company plans to proceed on the assumption that new Canadian legislative and regulatory climate change frameworks will be implemented regardless of the fate of Kyoto. The Federal Government has addressed the uncertainty around the ratification and implementation of Kyoto by providing the oil and gas sector with limits on the cost for large industrial emitters until 2012. For long-term, capital intensive investments, such as the Horizon Project, it is essential for the Company to understand the cost implications associated with the climate change policies beyond 2012. To address these concerns, the Federal Government outlined eight principles that would guide them in its negotiations and policies for the post 2012 years. On the basis of these principles, the Company will continue to work on the development plan of the Horizon Project. Accordingly, the Company will continue to develop strategies that will enable it to deal with the risks and opportunities associated with new climate change policies. In addition, the Company will work with relevant parties to ensure that new policies encourage innovation, energy efficiency, targeted research and development while not impacting Canada's competitive position. OIL AND NATURAL GAS RESERVES The Company retains qualified independent petroleum engineering consultants, Sproule Associates Limited ("Sproule"), to evaluate 100% of the Company's proved and probable crude oil and natural gas reserves and prepare Evaluation Reports on the Company's total reserves. The Company has been granted an exemption from the recently adopted National Instrument 51-101 -- Standards of Disclosure for Oil and Gas Activities ("NI 51-101") which prescribes standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This exemption allows the Company to substitute United States Securities and Exchange Commission ("SEC") requirements for certain disclosures required under NI 51-101. The primary difference between the two standards is the additional requirement under NI 51-101 to disclose proved and probable reserves and future net revenues using forecast prices and costs. The Company has elected to disclose proved reserves using constant prices and costs as mandated by the SEC and has also provided proved and probable reserves under the same parameters as voluntary additional information. Another difference between the two standards is in the definition of proved reserves. As discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the standards which NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the NI 51-101 and SEC standards is not material. The Company's Reserves Committee has met with Sproule and carried out independent due diligence procedures with Sproule as to the Company's reserves. Additional reserve disclosure is contained in the supplementary oil and gas information and the Company's Annual Information Form. SUBSEQUENT EVENT In February 2004, the Company announced the acquisition of certain resource properties in its North Alberta core region, collectively known as the Petrovera Partnership ("Petrovera"), for $467 million. Current production from the acquired properties is approximately 27,500 bbl/d of heavy oil and 9 mmcf/d of natural gas. Strategically, the acquisition fits with the Company's objective of dominating its core areas and related infrastructure. The Company expects to achieve operating cost reductions through synergies with its existing facilities including additional throughput in its 100% owned ECHO Pipeline. RISKS AND UNCERTAINTIES The Company is exposed to several operational risks inherent in exploring, developing, producing and marketing crude oil and natural gas. These inherent risks include: economic risk of finding and producing reserves at a reasonable cost; financial risk of marketing reserves at an acceptable price given current market conditions; cost of capital risk associated with securing the needed capital to carry out the Company's operations; risk of fluctuating foreign exchange rates; risk of carrying out operations with minimal environmental impact; risk of governmental policies, social instability or other political, economic or diplomatic developments in its international operations; and credit risk of non-payment for sales contracts or non-performance by counterparties to contracts. The Company uses a variety of means to help minimize these risks. The Company maintains a comprehensive insurance program to reduce risk to an acceptable level and to protect it against significant losses. Operational control is enhanced by focusing efforts on large core regions with high working interests and by assuming operatorship of all key facilities. Product mix is diversified, ranging from the production of natural gas to the production of crude oil of various grades. The Company believes this diversification reduces price risk when compared with over-leverage to one commodity. Sales of crude oil and natural gas are aimed at various markets to ensure that undue exposure to any one market does not exist. Financial instruments are utilized to help ensure targets are met and to manage commodity prices, foreign currency rates and interest rate exposure. The Company minimizes credit risks by entering into sales contracts and financial derivatives with only highly rated entities and financial institutions. In addition, the Company reviews its exposure to individual companies on a regular basis, and where appropriate ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. The Company's current position with respect to its financial instruments is detailed in note 10 to the consolidated financial statements. The arrangements and policies concerning the Company's financial instruments are under constant review and may change depending upon the prevailing market conditions. 54 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- The Company's capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist. The Company continues to employ an Environmental Management Plan (the "Plan") to ensure the welfare of its employees, the communities in which it operates, and the environment as a whole. Environmental protection is of fundamental importance and is undertaken in accordance with guiding principles approved by the Company's Board of Directors. A detailed copy of the Company's Plan is presented to, and reviewed by, the Board of Directors annually. The Plan is updated quarterly at the Directors' meetings. CRITICAL ACCOUNTING ESTIMATES Management is often required to make judgements, assumptions and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company. A comprehensive discussion of the Company's significant accounting policies is contained in note 1 to the consolidated financial statements. The following is a discussion of the accounting estimates that are critical in determining the Company's financial results. FULL COST ACCOUNTING The Company follows the full cost method of accounting for oil and natural gas properties and equipment as prescribed by the Canadian Institute of Chartered Accountants ("CICA"). Accordingly, all costs relating to the exploration for and development of oil and natural gas reserves are capitalized and accumulated in country-by-country cost centres. The capitalized costs and future capital costs related to each cost centre from which there is production are depleted on the unit-of-production method based on the estimated proved reserves of that country. Capitalized costs in each cost centre may not exceed the sum of undiscounted future net revenues from proved properties and the cost of unproved properties, net of provision for impairment, less estimated future financing and administrative expenses and income taxes (the "ceiling test"). If the net capitalized costs of a cost centre are determined to be in excess of the calculated ceiling, which is based largely on reserve estimates, the excess must be charged as an expense against net earnings. Proceeds on disposal of properties are ordinarily deducted from such costs without recognition of profit or loss except where such disposal constitutes a significant portion of the Company's reserves in that country. The alternate acceptable method of accounting for oil and natural gas properties and equipment is the successful efforts method. A major difference in applying the successful efforts method is that exploratory dry holes and geological and geophysical exploration costs would be charged against net earnings in the year incurred rather than being capitalized to property, plant and equipment. In addition, under this method cost centres are defined based on reserve pools rather than by country. OIL AND NATURAL GAS RESERVES The Company retains independent petroleum engineering consultants Sproule to evaluate the Company's proved and probable oil and natural gas reserves. In 2003, Sproule evaluated 100% of the Company's reserves. The estimation of reserves involves the exercise of judgement. Forecasts are based on engineering data, future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. The Company expects that over time its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels. Reserve estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and amortization. A revision to the reserve estimate could result in a higher or lower DD&A charge to net earnings. Downward revisions to reserve estimates could also result in a write-down of oil and natural gas property, plant and equipment under the ceiling test. FUTURE SITE RESTORATION The Company provides for the estimated future dismantlement, site restoration and abandonment costs of oil and natural gas properties using the unit-of-production method. Future site restoration costs for processing and production facilities are provided for using the straight-line method over their estimated lives. The annual provision is included in depletion, depreciation and amortization. The estimated site restoration costs are based on engineering estimates using current costs and technology in accordance with existing legislation and industry practice. The estimation of these costs can be affected by factors such as the number of wells drilled, well depth and area specific environmental legislation. These estimates are reviewed regularly and could impact the DD&A rate used by the Company. A revision to these estimated future costs could result in a higher or lower DD&A expense charged to net earnings. STOCK-BASED COMPENSATION The Company's Option Plan provides for granting of stock options to directors, officers and employees. Stock options granted under the Option Plan have a maximum term of six years to expiry and vest equally over a five-year period starting on the first anniversary date of the grant. The exercise price of each stock option granted is determined as the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the day of the grant. Each stock option granted permits the holder to purchase one common share of the Company at the stated exercise price. In June 2003, the Company approved a modification to its Option Plan. In lieu of receiving common shares, the stock option holder has the right to elect to receive a cash payment equal to the difference between the exercise price of the stock option and the market price of the Company's common shares on the date of surrender, multiplied by the number of common shares covered by the stock options surrendered. 55 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- The modification to the Option Plan was accounted for prospectively and for the year ended December 31, 2003, the Company recorded compensation expense of $200 million. As at December 31, 2003, the total liability for expected cash settlements under the Option Plan is $171 million, of which $130 million is included as a current liability. During the year ended December 31, 2003, cash payments of $31 million were made for 1,337,398 stock options surrendered. NEW ACCOUNTING STANDARDS FULL COST ACCOUNTING In September 2003, the CICA issued Accounting Guideline 16 "Oil and Gas Accounting - Full Cost". The Guideline modifies the ceiling test, which limits the aggregate capitalized costs that may be carried forward to future periods. Specific new guidance was provided on several issues, including the frequency of conducting cost centre impairment tests, the testing for cost centre recoverability and the method of determining fair value. The Guideline recommends that cost centre impairment tests should be conducted at each annual balance sheet date. Recovery of costs is tested by comparing the carrying amount of the oil and natural gas assets to the undiscounted cash flows from those assets using proved reserves and expected future prices and costs. If the carrying amount exceeds the recoverable amount, then impairment should be recognized on the amount by which the carrying amount of the assets exceeds the present value of expected cash flows using proved and probable reserves and expected future prices and costs. The effective date of the Guideline is for fiscal years beginning on or after January 1, 2004, with early adoption recommended. This guideline will apply to the ceiling test relating to the impairment of the Company's property, plant and equipment. Adoption of this standard would not have had an impact on the Company's consolidated financial statements for the year ended December 31, 2003. ASSET RETIREMENT OBLIGATIONS In January 2003, the CICA issued Section 3110 "Asset Retirement Obligations". The Section requires the recognition of the fair value of the retirement obligation for related long-term assets as a liability. Retirement costs equal to the retirement obligation are capitalized as part of the cost of the associated capital asset and amortized to expense through depletion over the life of the asset. In subsequent periods, the liability is adjusted for the passage of time and any changes in the amount or timing of the underlying future cash flows. This standard will be adopted retroactively effective January 1, 2004, and prior period comparative balances will be restated. Adoption of the standard will have the following effects on the Company's financial statements: ($ millions) January 1, 2004 - -------------------------------------------------------------------------------- Consolidated balance sheet Increase property, plant and equipment $ 445 Increase asset retirement obligation $ 450 Increase future income tax liability $ 3 Decrease foreign currency translation adjustment $ (14) Increase retained earnings $ 6 - -------------------------------------------------------------------------------- The Company's pipelines and co-generation plant have indeterminant lives and therefore the fair values of the related asset retirement obligations cannot be reasonably determined. The asset retirement obligation for these assets will be recorded in the year in which the lives of the assets are determinable. HEDGING RELATIONSHIPS In December 2001, the CICA issued Accounting Guideline 13, "Hedging Relationships". The effective date of this Guideline was deferred to fiscal years beginning on or after July 1, 2003. The Guideline addresses the types of items that qualify for hedge accounting, the formal documentation required to enable the use of hedge accounting and the requirement to evaluate hedges for effectiveness. The Guideline does not specify how hedge accounting should be applied but does require financial instruments that are not designated as hedges be recorded at fair value on the Company's consolidated balance sheet, with changes in fair value recorded in earnings. This Guideline will be adapted prospectively effective January 1, 2004 and will have the following effects on the Company's financial statements: ($ millions) January 1, 2004 - -------------------------------------------------------------------------------- Consolidated balance sheet Increase derivative financial instruments asset $ 16 Increase future income tax liability $ 7 Increase deferred revenue $ 9 - -------------------------------------------------------------------------------- OUTLOOK The Company continues its strategy of maintaining a large portfolio of varied projects, which enables the Company over an extended period of time to provide consistent growth in production and high shareholder returns. Annual budgets are developed, scrutinized throughout the year and changed if necessary in the context of project returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures in each of its project areas. The Company expects production levels in 2004 to average 1,320 to 1,395 mmcf/d of natural gas and 245,000 to 265,000 bbl/d of crude oil and NGLs, taking into account the Petrovera acquisition. First quarter 2004 production guidance for natural gas is 1,285 to 1,315 mmcf/d of natural gas and 263,000 to 283,000 bbl/d of crude oil and NGLs. 56 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - -------------------------------------------------------------------------------- The budgeted capital expenditures in 2004 are currently expected to be as follows: ($ millions) 2004 Budget - -------------------------------------------------------------------------------- North America natural gas $ 900 North America crude oil and NGLs 550 North Sea crude oil and NGLs 300 Offshore West Africa crude oil and NGLs 290 Property acquisitions and midstream 510 - -------------------------------------------------------------------------------- 2,550 Horizon Project (1) 200 - 400 - -------------------------------------------------------------------------------- Total $ 2,750 - 2,950 - -------------------------------------------------------------------------------- (1) Expenditure level is dependent upon timing of regulatory and Board of Director approvals. In 2004, the Company expects to drill approximately 706 net natural gas wells, 274 net crude oil wells and 321 stratigraphic test/service wells. The 2004 North America natural gas program will be highlighted by expanded drilling programs in the Northwest Alberta and Northeast British Columbia core regions as follows: (number of wells) 2004 Budget - -------------------------------------------------------------------------------- Northeast British Columbia 172 Northwest Alberta 145 North Alberta 183 South Alberta 206 - -------------------------------------------------------------------------------- Total 706 - -------------------------------------------------------------------------------- The Company continues the disciplined development of its heavy crude oil resources. These reserves will be developed as heavy crude oil markets permit. The 2004 drilling program consists of 110 conventional heavy crude oil wells, 51 thermal heavy crude oil wells, 43 light crude oil wells and 43 Pelican Lake crude oil wells. At Pelican Lake, the Enhanced Oil Recovery waterflood test program was a success and as such, the Company will begin the phased roll out of the waterflood with approximately 20% of the field being under waterflood by the end of 2004. The waterflood will stabilize production, but will require a further 63 Pelican Lake productive wells to be converted from producers to water injectors. Based upon the capital expenditure budget, the Company expects to incur Canadian current income tax expense in 2004 of $100 to $175 million. The 100% owned and operated Horizon Project is expected to be built in three phases and produce approximately 232,000 bbl/d of light, sweet synthetic crude oil. In 2004, the third phase of engineering, EDS, is expected to be completed. In addition, the financing plan will be optimized and finalized by the third quarter of 2004. The 2004 capital budget for the Horizon Project will be phased in over the year and is dependent upon regulatory approval and cost estimates. Regulatory review for the environmental assessment of the Horizon Project was conducted in September 2003 and the Company received approval from the review panel in January 2004. Final regulatory approvals are expected in the first half of 2004. With final regulatory approval, the completion of the EDS and confirmation of cost estimates, Board of Director approval will be sought in late 2004. Depending upon the timing of final approval, a total of $200 to $400 million is budgeted for the Horizon Project in 2004. The Company anticipates that 80% of the detailed engineering will be completed before it commits to the construction of the Horizon Project. The capital budget in 2004 for the North Sea is $300 million and includes the drilling of approximately 13 crude oil wells, implementing a secondary recovery natural gas injection scheme at Banff, optimizing Ninian and Murchison waterfloods, and building on the successful 2003 recompletion program. Average crude oil production is expected to remain relatively consistent with current production levels; however, natural gas volumes will be lower as natural gas sales at Banff are diverted to reinjection. In 2004, the capital budget for Offshore West Africa is set at $290 million, of which the Company anticipates $220 million to be spent on the continuing development of the Baobab Field in Cote d'Ivoire. The remainder will be spent on the pre-development work associated with the West Espoir development and various exploration activities. The original budget was based on an average natural gas price of $5.50 per GJ at AECO, an oil price of US$26.00 per bbl for WTI and a heavy oil differential of US$8.50 per bbl. The current price-deck for our products, if maintained, could result in a significant increase in cash flow over the budget. The Company will monitor its expected cash flow excess and intends to allocate a minimum of 50% of such excess towards debt repayment. The remaining excess will be directed to the Company's authorized share buy-back program and additional expenditures on conventional crude oil and natural gas opportunities. Such expenditures will only be incurred as excess cash flows are realized and will be subject to the same economic tests as regular budgeted expenditures. It is expected that the largest portion of the additional capital expenditures will take place late in the third and fourth quarters of 2004 and accordingly will not add materially to the Company's 2004 average production volumes. Should additional economic opportunities for share buy-backs or capital activities not present themselves to the extent allocated, such allocations of excess cash flow would revert to debt repayment. 57 ANNUAL REPORT 2003 - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - --------------------------------------------------------------------------------
SENSITIVITY ANALYSIS (1) CASH FLOW FROM CASH FLOW FROM OPERATIONS (2) OPERATIONS (2) NET EARNINGS (2) NET EARNINGS (2) ($ millions) ($/share, basic) ($ millions) ($/share, basic) - ---------------------------------------------------------------------------------------------------------------------------------- PRICE CHANGES Crude oil - WTI US$1.00/bbl (3) Excluding financial derivatives $ 88 $ 0.66 $ 63 $ 0.47 Including financial derivatives $ 65 - 88 $ 0.48 - 0.66 $ 46 - 63 $ 0.34 - 0.47 Natural gas - AECO C$0.10/mcf (3) Excluding financial derivatives $ 35 $ 0.26 $ 21 $ 0.16 Including financial derivatives $ 32 - 34 $ 0.24 - 0.25 $ 19 - 21 $ 0.14 - 0.16 VOLUME CHANGES Crude oil - 10,000 bbl/d $ 50 $ 0.37 $ 17 $ 0.12 Natural gas - 10 mmcf/d $ 13 $ 0.10 $ 5 $ 0.04 FOREIGN CURRENCY RATE CHANGE $0.01 change in C$ in relation to US$ (3) Excluding financial derivatives $ 48 $ 0.36 $ 15 $ 0.11 Including financial derivatives $ 41 - 44 $ 0.31 - 0.33 $ 10 - 13 $ 0.08 - 0.09 INTEREST RATE CHANGE - 1% $ 10 $ 0.08 $ 10 $ 0.08 - ----------------------------------------------------------------------------------------------------------------------------------
(1) The sensitivities are calculated based on 2003 fourth quarter results. (2) Attributable to common shareholders. (3) For details of financial instruments in place, see consolidated financial statements note 10.
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES Q1 Q2 Q3 Q4 2003 2002 2001 - ---------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS (bbl/d) North America 173,045 175,232 174,838 176,429 174,895 169,675 166,675 North Sea 56,963 55,781 60,193 54,529 56,869 38,876 36,252 Offshore West Africa 7,552 9,594 11,985 13,304 10,628 6,784 3,396 - ---------------------------------------------------------------------------------------------------------------------------------- Total 237,560 240,607 247,016 244,262 242,392 215,335 206,323 - ---------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS (mmcf/d) North America 1,265 1,278 1,229 1,206 1,245 1,204 906 North Sea 41 40 49 52 46 27 12 Offshore West Africa 4 7 11 12 8 1 -- - ---------------------------------------------------------------------------------------------------------------------------------- Total 1,310 1,325 1,289 1,270 1,299 1,232 918 - ---------------------------------------------------------------------------------------------------------------------------------- BARRELS OF OIL EQUIVALENT (boe/d) North America 383,952 388,210 379,751 377,448 382,315 370,337 317,658 North Sea 63,764 62,507 68,323 63,246 64,469 43,391 38,293 Offshore West Africa 8,236 10,738 13,808 15,241 12,030 6,994 3,396 - ---------------------------------------------------------------------------------------------------------------------------------- Total 455,952 461,455 461,882 455,935 458,814 420,722 359,347 - ---------------------------------------------------------------------------------------------------------------------------------- PER UNIT RESULTS Q1 Q2 Q3 Q4 2003 2002 2001 - ---------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl) Sales price $35.26 $30.27 $30.97 $30.02 $31.59 $29.76 $24.31 Royalties 3.56 2.78 2.56 2.22 2.77 3.16 2.17 Production expense 10.79 10.80 10.14 9.45 10.28 8.45 7.64 - ---------------------------------------------------------------------------------------------------------------------------------- Netback $20.91 $16.69 $18.27 $18.35 $18.54 $18.15 $14.50 - ---------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/mcf) Sales price $ 7.25 $ 6.12 $ 5.50 $ 5.23 $ 6.02 $ 3.76 $5.16 Royalties 1.78 1.35 1.11 1.05 1.32 0.78 1.25 Production expense 0.57 0.59 0.63 0.63 0.60 0.57 0.51 - ---------------------------------------------------------------------------------------------------------------------------------- Netback $ 4.90 $ 4.18 $ 3.76 $ 3.55 $ 4.10 $ 2.41 $3.40 - ---------------------------------------------------------------------------------------------------------------------------------- BARRELS OF OIL EQUIVALENT ($/boe) Sales price $39.24 $33.32 $31.94 $30.64 $33.75 $26.25 $27.15 Royalties 6.96 5.32 4.46 4.12 5.20 3.91 4.42 Production expense 7.27 7.34 7.17 6.81 7.15 5.99 5.69 - ---------------------------------------------------------------------------------------------------------------------------------- Netback $25.01 $20.66 $20.31 $19.71 $21.40 $16.35 $17.04 - ----------------------------------------------------------------------------------------------------------------------------------
58 CANADIAN NATURAL - -------------------------------------------------------------------------------- MANAGEMENT'S DISCUSSION AND ANALYSIS - --------------------------------------------------------------------------------
NETBACK ANALYSIS ($/boe, except daily production) 2003 2002 2001 - --------------------------------------------------------------------------------------------------------- Daily production, before royalties (boe/d) 458,814 420,722 359,347 Sales price $ 33.75 $ 26.25 $ 27.15 Royalties 5.20 3.91 4.42 Production expense 7.15 5.99 5.69 - --------------------------------------------------------------------------------------------------------- NETBACK 21.40 16.35 17.04 Midstream contribution (0.28) (0.25) (0.12) Administration 0.52 0.40 0.29 Interest 0.94 1.03 1.05 Realized foreign exchange loss (gain) 0.05 0.02 (0.01) Taxes other than income tax (current) 0.69 0.35 0.53 Current income tax (North Sea) 0.14 (0.13) 0.47 Current income tax (Offshore West Africa) 0.06 0.04 -- Current income tax (North America) 0.26 -- -- Current income tax (Large Corporations Tax) 0.09 0.14 0.11 - --------------------------------------------------------------------------------------------------------- Cash flow $ 18.93 $ 14.75 $ 14.72 - --------------------------------------------------------------------------------------------------------- QUARTERLY FINANCIAL INFORMATION ($ millions, except per share amounts) Q1 Q2 Q3 Q4 TOTAL - ------------------------------------------------------------------------------------------------------------------------------------ 2003 Revenue $ 1,693.00 $ 1,477.00 $ 1,434.00 $ 1,368.00 $ 5,972.00 Cash flow from operations attributable to common shareholders $ 906.00 $ 762.00 $ 758.00 $ 734.00 $ 3,160.00 Per common share - basic $ 6.76 $ 5.68 $ 5.62 $ 5.48 $ 23.54 - diluted $ 6.53 $ 5.57 $ 5.56 $ 5.42 $ 23.06 Net earnings attributable to common shareholders $ 428.00 $ 525.00 $ 203.00 $ 251.00 $ 1,407.00 Per common share - basic $ 3.19 $ 3.91 $ 1.51 $ 1.87 $ 10.48 - diluted $ 3.03 $ 3.78 $ 1.49 $ 1.83 $ 10.14 - ------------------------------------------------------------------------------------------------------------------------------------ 2002 Revenue $ 782.00 $ 924.00 $ 1,239.00 $ 1,397.00 $ 4,342.00 Cash flow from operations attributable to common shareholders $ 359.00 $ 475.00 $ 643.00 $ 777.00 $ 2,254.00 Per common share - basic $ 2.95 $ 3.86 $ 4.83 $ 5.81 $ 17.63 - diluted $ 2.85 $ 3.70 $ 4.71 $ 5.62 $ 16.99 Net earnings attributable to common shareholders $ 99.00 $ 145.00 $ 117.00 $ 209.00 $ 570.00 Per common share - basic $ 0.81 $ 1.18 $ 0.88 $ 1.56 $ 4.46 - diluted $ 0.79 $ 1.09 $ 0.86 $ 1.51 $ 4.31 - ------------------------------------------------------------------------------------------------------------------------------------ TRADING AND SHARE STATISTICS Q1 Q2 Q3 Q4 2003 TOTAL 2002 Total - ----------------------------------------------------------------------------------------------------------------------------------- TSX - C$ Trading volume (thousands) 45,742 36,859 30,386 34,688 147,675 154,829 Share price ($/share) High $ 52.90 57.39 57.29 67.22 67.22 54.54 Low $ 45.20 46.55 51.23 53.31 45.20 37.60 Close $ 50.15 53.75 55.59 65.37 65.37 46.80 Market capitalization at December 31 ($ millions) 8,742.00 6,261.00 Shares outstanding (thousands) 133,731.00 133,776.00 - ----------------------------------------------------------------------------------------------------------------------------------- NYSE - US$ Trading volume (thousands) 2,539 2,546 2,760 3,884 11,729 7,966 Share price ($/share) High $ 35.97 $ 42.45 $ 41.35 $ 51.39 $ 51.39 $ 34.88 Low $ 29.25 $ 31.51 $ 36.50 $ 40.44 $ 29.25 $ 23.55 Close $ 34.00 $ 39.91 $ 41.16 $ 50.44 $ 50.44 $ 29.67 Market capitalization at December 31 ($ millions) $ 6,745 $ 3,969 Shares outstanding (thousands) $133,731 $133,776 - -----------------------------------------------------------------------------------------------------------------------------------
59 ANNUAL REPORT 2003 EX-99 5 ex3-form40f_2003.txt EXHIBIT 3 EXHIBIT 3 --------- - ------------------------------------ ----------------------------------------- MANAGEMENT'S REPORT AND AUDITORS' REPORT - ------------------------------------ ----------------------------------------- MANAGEMENT'S REPORT The accompanying consolidated financial statements and all information in the annual report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies in the notes to the consolidated financial statements. Where necessary, management has made informed judgements and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the financial statements have been prepared in accordance with Canadian generally accepted accounting principles appropriate in the circumstances. The financial information elsewhere in the annual report has been reviewed to ensure consistency with that in the consolidated financial statements. Management maintains appropriate systems of internal control. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorized, assets are safeguarded from loss or unauthorized use and financial records are properly maintained to provide reliable information for preparation of financial statements. PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has been engaged, as approved by a vote of the shareholders at the Company's most recent Annual General Meeting, to examine the consolidated financial statements in accordance with generally accepted auditing standards in Canada and provide an independent professional opinion. Their report is presented with the consolidated financial statements. The Board of Directors (the "Board") is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board exercises this responsibility through the Audit Committee of the Board. This committee, which is comprised of non-management directors, meets with management and the external auditors to satisfy itself that management responsibilities are properly discharged and to review the consolidated financial statements before they are presented to the Board for approval. The consolidated financial statements have been approved by the Board on the recommendation of the Audit Committee. /s/ JOHN G. LANGILLE /s/ DOUGLAS A. PROLL /s/ RANDALL S. DAVIS JOHN G. LANGILLE CA DOUGLAS A. PROLL CA RANDALL S. DAVIS CA President & Director Senior Vice President, Finance Financial Controller February 19, 2004 AUDITORS' REPORT TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED, We have audited the consolidated balance sheets of Canadian Natural Resources Limited as at December 31, 2003 and 2002 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles. /s/ PricewaterhouseCoopers LLP Calgary, Alberta, Canada Chartered Accountants February 19, 2004 60 CANADIAN NATURAL - ------------------------------------ ----------------------------------------- CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------ ----------------------------------------- CONSOLIDATED BALANCE SHEETS AS AT DECEMBER 31 (millions of Canadian dollars) 2003 2002 ================================================================================ ASSETS CURRENT ASSETS - -------------------------------------------------------------------------------- Cash $ 104 $ 30 - -------------------------------------------------------------------------------- Accounts receivable and other 751 745 ================================================================================ 855 775 - -------------------------------------------------------------------------------- PROPERTY, PLANT AND EQUIPMENT (note 2) 13,269 12,500 - -------------------------------------------------------------------------------- DEFERRED CHARGES 74 84 ================================================================================ $ 14,198 $ 13,359 ================================================================================ LIABILITIES CURRENT LIABILITIES - -------------------------------------------------------------------------------- Accounts payable $ 464 $ 337 - -------------------------------------------------------------------------------- Accrued liabilities 712 428 - -------------------------------------------------------------------------------- Current portion of long-term debt (note 3) 184 24 ================================================================================ 1,360 789 - -------------------------------------------------------------------------------- LONG-TERM DEBT (note 3) 2,645 4,074 - -------------------------------------------------------------------------------- DEFERRED CREDITS (note 4) 488 440 - -------------------------------------------------------------------------------- FUTURE INCOME TAX (note 5) 3,588 3,188 ================================================================================ 8,081 8,491 ================================================================================ SHAREHOLDERS' EQUITY PREFERRED SECURITIES (note 6) 103 126 - -------------------------------------------------------------------------------- SHARE CAPITAL (note 7) 2,353 2,304 - -------------------------------------------------------------------------------- RETAINED EARNINGS 3,644 2,414 - -------------------------------------------------------------------------------- FOREIGN CURRENCY TRANSLATION ADJUSTMENT (note 8) 17 24 ================================================================================ 6,117 4,868 ================================================================================ $ 14,198 $ 13,359 ================================================================================ COMMITMENTS (note 11) Signed on behalf of the Board: /s/ GORDON D. GIFFIN /s/ N. MURRAY EDWARDS AMBASSADOR GORDON D. GIFFIN N. MURRAY EDWARDS Chairman of the Audit Committee Vice-Chairman of the Board of Directors and Director and Director 61 ANNUAL REPORT 2003 Consolidated financial statements
CONSOLIDATED STATEMENTS OF EARNINGS FOR THE YEARS ENDED DECEMBER 31 (millions of Canadian dollars, except per common share amounts) 2003 2002 2001 ============================================================================================================= REVENUE $ 5,972 $ 4,342 $ 3,757 - ------------------------------------------------------------------------------------------------------------- Less: royalties (872) (600) (580) ============================================================================================================= 5,100 3,742 3,177 ============================================================================================================= EXPENSES - ------------------------------------------------------------------------------------------------------------- Production 1,209 931 756 - ------------------------------------------------------------------------------------------------------------- Transportation 262 262 170 - ------------------------------------------------------------------------------------------------------------- Depletion, depreciation and amortization 1,565 1,314 903 - ------------------------------------------------------------------------------------------------------------- Administration 87 61 38 - ------------------------------------------------------------------------------------------------------------- Stock-based compensation (note 7) 200 -- -- - ------------------------------------------------------------------------------------------------------------- Interest 157 159 138 - ------------------------------------------------------------------------------------------------------------- Foreign exchange (gain) loss (312) (31) 63 - ------------------------------------------------------------------------------------------------------------- Loss on sale of United States assets (note 2) -- -- 24 ============================================================================================================= 3,168 2,696 2,092 ============================================================================================================= EARNINGS BEFORE TAXES 1,932 1,046 1,085 - ------------------------------------------------------------------------------------------------------------- Taxes other than income tax (note 5) 107 63 69 - ------------------------------------------------------------------------------------------------------------- Current income tax (note 5) 92 8 77 - ------------------------------------------------------------------------------------------------------------- Future income tax (note 5) 339 400 283 ============================================================================================================= NET EARNINGS 1,394 575 656 - ------------------------------------------------------------------------------------------------------------- Dividend on preferred securities, net of tax (5) (6) (6) - ------------------------------------------------------------------------------------------------------------- Revaluation of preferred securities, net of tax 18 1 (8) ============================================================================================================= NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 1,407 $ 570 $ 642 ============================================================================================================= NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS PER COMMON SHARE (note 9) - ------------------------------------------------------------------------------------------------------------- Basic $ 10.48 $ 4.46 $ 5.30 - ------------------------------------------------------------------------------------------------------------- Diluted $ 10.14 $ 4.31 $ 5.17 ============================================================================================================= CONSOLIDATED STATEMENTS OF RETAINED EARNINGS FOR THE YEARS ENDED DECEMBER 31 (millions of Canadian dollars) 2003 2002 2001 ============================================================================================================= BALANCE - BEGINNING OF YEAR $ 2,414 $ 1,908 $ 1,391 - ------------------------------------------------------------------------------------------------------------- Net earnings 1,394 575 656 - ------------------------------------------------------------------------------------------------------------- Dividend on preferred securities, net of tax (5) (6) (6) - ------------------------------------------------------------------------------------------------------------- Revaluation of preferred securities, net of tax 18 1 (8) - ------------------------------------------------------------------------------------------------------------- Dividend on common shares (note 7) (81) (64) (49) - ------------------------------------------------------------------------------------------------------------- Purchase of common shares (note 7) (96) -- (76) ============================================================================================================= BALANCE - END OF YEAR $ 3,644 $ 2,414 $ 1,908 =============================================================================================================
62 CANADIAN NATURAL
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31 (millions of Canadian dollars) 2003 2002 2001 ============================================================================================================= OPERATING ACTIVITIES - ------------------------------------------------------------------------------------------------------------- Net earnings $ 1,394 $ 575 $ 656 - ------------------------------------------------------------------------------------------------------------- Non-cash items - ------------------------------------------------------------------------------------------------------------- Depletion, depreciation and amortization 1,565 1,314 903 - ------------------------------------------------------------------------------------------------------------- Stock-based compensation 200 -- -- - ------------------------------------------------------------------------------------------------------------- Unrealized foreign exchange (gain) loss (320) (35) 64 - ------------------------------------------------------------------------------------------------------------- Deferred petroleum revenue tax (9) 10 -- - ------------------------------------------------------------------------------------------------------------- Future income tax 339 400 283 - ------------------------------------------------------------------------------------------------------------- Loss on sale of United States assets -- -- 24 ============================================================================================================= Cash flow provided from operations 3,169 2,264 1,930 - ------------------------------------------------------------------------------------------------------------- Deferred charges 10 (84) -- - ------------------------------------------------------------------------------------------------------------- Net change in non-cash working capital (note 12) (48) (157) (42) ============================================================================================================= 3,131 2,023 1,888 ============================================================================================================= FINANCING ACTIVITIES - ------------------------------------------------------------------------------------------------------------- Repayment of bank credit facilities (647) (1,234) (442) - ------------------------------------------------------------------------------------------------------------- Repayment of senior unsecured notes (85) (16) (16) - ------------------------------------------------------------------------------------------------------------- Issue of US dollar debt securities -- 1,749 615 - ------------------------------------------------------------------------------------------------------------- Repayment of obligations under capital leases (8) (4) -- - ------------------------------------------------------------------------------------------------------------- Repayment of limited recourse loan -- -- (12) - ------------------------------------------------------------------------------------------------------------- Dividend on preferred securities (9) (10) (10) - ------------------------------------------------------------------------------------------------------------- Dividend on common shares (77) (60) (36) - ------------------------------------------------------------------------------------------------------------- Issue of common shares on exercise of stock options 89 84 43 - ------------------------------------------------------------------------------------------------------------- Purchase of common shares (144) -- (113) - ------------------------------------------------------------------------------------------------------------- Net change in non-cash working capital (note 12) (11) 27 7 ============================================================================================================= (892) 536 36 ============================================================================================================= INVESTING ACTIVITIES - ------------------------------------------------------------------------------------------------------------- Business combination, net of cash acquired (note 13) -- (843) -- - ------------------------------------------------------------------------------------------------------------- Expenditures on property, plant and equipment (2,526) (1,752) (1,948) - ------------------------------------------------------------------------------------------------------------- Net proceeds on sale of property, plant and equipment 20 76 63 ============================================================================================================= Net expenditures on property, plant and equipment (2,506) (2,519) (1,885) - ------------------------------------------------------------------------------------------------------------- Net change in non-cash working capital (note 12) 341 (25) (52) ============================================================================================================= (2,165) (2,544) (1,937) ============================================================================================================= INCREASE (DECREASE) IN CASH 74 15 (13) - ------------------------------------------------------------------------------------------------------------- CASH - BEGINNING OF YEAR 30 15 28 ============================================================================================================= CASH - END OF YEAR $ 104 $ 30 $ 15 =============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (note 12) 63 ANNUAL REPORT 2003 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (tabular amounts in millions of Canadian dollars, unless otherwise stated) 1. ACCOUNTING POLICIES Canadian Natural Resources Limited (the "Company") is a senior independent oil and natural gas exploration, development and production company based in Calgary, Alberta, Canada. The Company's operations are focused in North America, largely in western Canada, the North Sea and Offshore West Africa. Within western Canada, the Company is developing its Horizon Oil Sands Project (the "Horizon Project") and maintains its midstream activities. The Horizon Project involves a plan to recover bitumen through mining operations, while the midstream activities include the Company's pipeline operations and an electricity co-generation system. The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in Canada. A summary of differences between accounting principles in Canada and those generally accepted in the United States ("US") is contained in note 16. Significant accounting policies are summarized as follows: PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and all of its subsidiaries and partnerships. A significant portion of the Company's activities are conducted jointly with others and the consolidated financial statements reflect only the Company's proportionate interest in such activities. MEASUREMENT UNCERTAINTY Management has made estimates and assumptions regarding certain assets, liabilities, revenues and expenses in the preparation to the consolidated financial statements. Such estimates primarily relate to unsettled transactions and events as of the date to the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. Depletion, depreciation and amortization and amounts used for ceiling test calculations are based on estimates of proved oil and natural gas reserves and commodity prices, production expenses and capital costs required to develop and produce those reserves. The majority of the Company's reserve estimates are evaluated annually by independent engineering firms. By their nature, estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the consolidated financial statements of future periods could be material. The measurement of petroleum revenue tax expense and the related provision in the consolidated financial statements are subject to uncertainty associated with future recoverability of oil and natural gas reserves, commodity prices and the timing of future events, which could result in material changes to deferred amounts. CASH Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with a term to maturity of three months or less from the transaction date are reported as cash equivalents. PROPERTY, PLANT AND EQUIPMENT The Company follows the full cost method of accounting for oil and natural gas properties and equipment as prescribed by the Canadian Institute of Chartered Accountants ("CICA"). Accordingly, all costs relating to the exploration for and development of oil and natural gas reserves are capitalized and accumulated in country-by-country cost centres. Administrative overhead incurred during the development phase of large capital projects is capitalized until commercial production commences. Proceeds on disposal of properties are ordinarily deducted from such costs without recognition of profit or loss except where such disposal constitutes a significant portion of the Company's reserves in that country. All costs associated with the Horizon Project during its development stage are capitalized. DEPLETION, DEPRECIATION AND AMORTIZATION The costs related to each cost centre from which there is production are depleted on the unit-of-production method based on the estimated proved reserves of that country. Volumes of net production and net reserves before royalties are converted to equivalent units on the basis of estimated relative energy content. In determining its depletion base, the Company includes estimated future costs to be incurred in developing proved reserves and excludes the cost of unproved properties. The unproved properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the value of the unproved property is considered to be impaired, the cost of the unproved property or the amount of the impairment is added to costs subject to depletion. Certain costs in cost centres from which there has been no commercial production are not subject to depletion until commercial production commences. Processing and production facilities are depreciated on a straight-line basis over their estimated lives. The Company carries its oil and natural gas properties at the lower of net capitalized cost and net recoverable amount (the "ceiling test"). The net capitalized cost of each cost centre is calculated as the net book value of the related assets less the accumulated provisions for future income taxes and future site restoration. Net recoverable amount is limited to the sum of undiscounted future net revenues from proved properties and the cost of unproved properties net of provisions for impairment less estimated future financing and administrative expenses and income taxes. Future net revenues are based on sales prices and costs prevailing at year end. 64 CANADIAN NATURAL The Company carries its midstream assets at the lower of net capitalized cost and fair value. Midstream assets are depreciated on a straight-line basis over their estimated lives. Head office capital assets are amortized on a declining balance basis over their estimated useful lives. DEFERRED CHARGES Deferred charges include deferred financing costs associated with the issuance of long-term debt and settlement costs of long-term natural gas contracts. Deferred charges are amortized over the original term of the related instrument. FUTURE SITE RESTORATION Estimated future dismantlement, site restoration and abandonment costs ("site restoration costs") for oil and natural gas properties are provided for using the unit-of-production method. Future site restoration costs for processing and production facilities are provided for on a straight-line basis over their estimated lives. The estimated site restoration costs are based on engineering estimates using current costs and technology in accordance with current legislation and industry practice. The annual provision is included in depletion, depreciation and amortization. Actual site restoration costs incurred to dismantle the processing and production facilities and restore well sites are charged against the related future site restoration liability. FOREIGN CURRENCY TRANSLATION Foreign operations that are self-sustaining are translated using the current rate method. Under this method, assets and liabilities are translated to Canadian dollars from their functional currency using the exchange rate in effect at the consolidated balance sheet date. Revenues and expenses are translated to Canadian dollars at the monthly average exchange rates. Gains or losses on translation are included in the foreign currency translation adjustment in shareholders' equity in the consolidated balance sheets. Foreign operations that are integrated are translated using the temporal method. For foreign currency balances and integrated subsidiaries, monetary assets and liabilities are translated to Canadian dollars at the exchange rate in effect at the consolidated balance sheet date and non-monetary assets and liabilities are translated at the rate of exchange in effect when the assets were acquired or obligations incurred. Revenues and expenses are translated to Canadian dollars at the monthly average exchange rates. Provisions for depletion, depreciation and amortization are translated at the same rate as the related items. Gains or losses on the translation of long-term debt denominated in US dollars are either recognized in net earnings immediately, or in the foreign currency translation adjustment (note 8) for translation gains or losses on that portion of the US dollar denominated debt designated as a hedge of self-sustaining foreign operations PETROLEUM REVENUE TAX The Company accounts for future United Kingdom petroleum revenue tax ("PRT") by the life-of-the-field method. The total future liability or recovery of PRT is estimated using current sales prices and costs. The estimated future PRT is apportioned to accounting periods on the basis of total estimated future revenues. Changes in the estimated total future PRT are accounted for prospectively. PRODUCTION SHARING CONTRACT Production generated from offshore Cote d'Ivoire is shared by the terms of the Production Sharing Contract ("PSC") with the State Oil Company of Cote d'Ivoire ("Petroci"). Revenues are divided into cost recovery revenues and profit revenues. Cost recovery revenues allow the Company to recover the capital and operating costs carried by the Company on behalf of Petroci. These revenues are reported as sales revenues. Profit revenues are allocated to joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Cote d'Ivoire Government. The Government's share of revenues attributable to the Company's equity interest is reported as either a royalty expense or a current tax expense in accordance with the PSC. INCOME TAX The Company follows the liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted on the consolidated balance sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is recognized in net earnings in the period of the change. REVENUE RECOGNITION Revenues are recognized when products have been delivered or services have been performed. STOCK-BASED COMPENSATION PLANS As a result of modifications to its Stock Option Plan (note 7) in the second quarter of 2003, the Company prospectively adopted the following accounting policy with respect to stock-based compensation: 65 ANNUAL REPORT 2003 Notes to the consolidated financial statements The Company accounts for its stock-based compensation using the intrinsic value method. A liability for expected cash settlements under the Company's Stock Option Plan (the "Option Plan) is accrued over the vesting period of the stock options based on the difference between the exercise price of the stock options and the market price of the Company's common shares. The liability is revalued quarterly to reflect changes in the market price of the Company's common shares and the net change is recognized in net earnings. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by employees, officers or directors and the previously recognized liability associated with the stock options is recorded as share capital. The Company also has an employee stock savings plan. Contributions to the employee stock savings plan are recorded as compensation expense at the time of the contribution. FINANCIAL INSTRUMENTS Financial instruments are utilized by the Company to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for trading or other speculative purposes. The Company's policy is to formally document relationships between hedging instruments and hedged items, the risk management objective, and the strategy for undertaking various hedge transactions. The Company assesses whether the financial instruments entered into are highly effective as fair value or cash flow hedges, both at the inception of the hedge and over the term of the financial instrument. The Company enters into commodity price contracts to hedge anticipated sales of oil and natural gas production in order to protect cash flow for capital expenditure programs. Gains or losses on these contracts are included in oil and natural gas revenue at the time of sale of the related product. Foreign exchange translation gains and losses on foreign currency denominated financial instruments used to hedge anticipated US dollar denominated oil and natural gas sales are recognized in revenue at the time of sale of the related product. The Company enters into interest rate swap agreements to manage its fixed to floating interest rate mix on long-term debt. The interest rate swap agreements require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. Gains or losses on these financial instruments are included in interest expense in the consolidated statement of earnings when realized. The related amount receivable from or payable to counterparties is included as an adjustment to accrued interest in the consolidated balance sheets. The Company assumed, through the Rio Alto acquisition, a foreign currency swap agreement that hedges a foreign currency denominated long-term debt instrument through an offsetting forward exchange contract. The foreign exchange translation gains and losses on the financial instrument are used to offset the respective translation gains and losses recognized on the long-term debt. Realized gains and losses on the termination of financial instruments that have been accounted for as hedges are deferred under non-current assets or liabilities on the consolidated balance sheets and recognized in net earnings in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized gain or loss is recognized in net earnings. PER COMMON SHARE AMOUNTS The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. This method assumes that proceeds received from the exercise of in-the-money stock options not included as a liability and other dilutive instruments are used to purchase common shares at the average market price during the year. COMPARATIVE FIGURES Certain figures provided for prior years have been reclassified to conform to the presentation adopted in 2003. In accordance will EIC 123 "Reporting Revenue Gross as a Principal Versus Net as an Agent" of the Emerging Issues Committee of the CICA, transportation costs are no longer netted against revenue but are disclosed as a separate expense in the consolidated statements of earnings. 2. PROPERTY, PLANT AND EQUIPMENT 2003 - -------------------------------------------------------------------------------- ACCUMULATED DEPLETION AND COST DEPRECIATION NET ================================================================================ Oil and natural gas North America $ 15,632 $ 4,791 $ 10,841 - -------------------------------------------------------------------------------- North Sea 1,642 485 1,157 - -------------------------------------------------------------------------------- Offshore West Africa 788 137 651 - -------------------------------------------------------------------------------- Horizon Project 381 -- 381 - -------------------------------------------------------------------------------- Midstream 225 25 200 - -------------------------------------------------------------------------------- Head office 70 31 39 ================================================================================ $ 18,738 $ 5,469 $ 13,269 ================================================================================ 66 CANADIAN NATURAL 2002 - -------------------------------------------------------------------------------- ACCUMULATED DEPLETION AND COST DEPRECIATION NET ================================================================================ Oil and natural gas - -------------------------------------------------------------------------------- North America $ 13,863 $ 3,611 $ 10,252 - -------------------------------------------------------------------------------- North Sea 1,621 344 1,277 - -------------------------------------------------------------------------------- Offshore West Africa 612 94 518 - -------------------------------------------------------------------------------- Horizon Project 229 -- 229 - -------------------------------------------------------------------------------- Midstream 214 18 196 - -------------------------------------------------------------------------------- Head office 50 22 28 ================================================================================ $ 16,589 $ 4,089 $ 12,500 ================================================================================ During the year ended December 31, 2003, the Company capitalized administrative overhead of $12 million (2002 - $13 million, 2001 - $7 million) relating to exploration and development in the North Sea and Offshore West Africa and $23 million (2002 - $4 million, 2001 - $nil) relating to the Horizon Project in North America. During 2001, the Company sold a large portion of its properties in the United States and recorded a loss on sale of $24 million. Included in property, plant and equipment are unproved land and projects under development that are not subject to depletion or depreciation:
2003 2002 ====================================================================================== Oil and natural gas - -------------------------------------------------------------------------------------- North America $ 789 $ 667 - -------------------------------------------------------------------------------------- North Sea 56 62 - -------------------------------------------------------------------------------------- Offshore West Africa 237 132 - -------------------------------------------------------------------------------------- Horizon Project 381 229 ====================================================================================== $ 1,463 $ 1,090 ====================================================================================== 3. LONG-TERM DEBT 2003 2002 ====================================================================================== Bank credit facilities - -------------------------------------------------------------------------------------- Bankers' acceptances $ -- $ 728 - -------------------------------------------------------------------------------------- US dollar bankers' acceptances (2003 - US$207 million, 2002 - US$150 million) 268 237 - -------------------------------------------------------------------------------------- Medium-term notes - -------------------------------------------------------------------------------------- 6.85% unsecured debentures due May 28, 2004 125 125 - -------------------------------------------------------------------------------------- 7.40% unsecured debentures due March 1, 2007 125 125 - -------------------------------------------------------------------------------------- Senior unsecured notes - -------------------------------------------------------------------------------------- 6.95% due September 30, 2003 (2003 - US$nil, 2002 - US$10 million) -- 16 - -------------------------------------------------------------------------------------- 6.42% due May 27, 2004 (US$40 million) 52 63 - -------------------------------------------------------------------------------------- 7.69% due December 19, 2005 (US$125 million) 194 194 - -------------------------------------------------------------------------------------- 6.50% due May 1, 2008 (2003 - US$nil , 2002 - US$50 million) -- 79 - -------------------------------------------------------------------------------------- Adjustable rate due May 27, 2009 (US$93 million) 120 146 - -------------------------------------------------------------------------------------- US dollar debt securities - -------------------------------------------------------------------------------------- 6.70% due July 15, 2011 (US$400 million) 517 632 - -------------------------------------------------------------------------------------- 5.45% due October 1, 2012 (US$350 million) 452 553 - -------------------------------------------------------------------------------------- 7.20% due January 15, 2032 (US$400 million) 517 632 - -------------------------------------------------------------------------------------- 6.45% due June 30, 2033 (US$350 million) 452 553 - -------------------------------------------------------------------------------------- Obligations under capital leases 7 15 ====================================================================================== 2,829 4,098 - -------------------------------------------------------------------------------------- Less: current portion of long-term debt 184 24 ====================================================================================== $ 2,645 $ 4,074 ======================================================================================
67 ANNUAL REPORT 2003 Notes to the consolidated financial statements BANK CREDIT FACILITIES The Company has unsecured bank credit facilities of $1,925 million, comprised of a $100 million operating demand facility and a revolving credit and term loan facility of $1,825 million. The revolving credit and term loan facility is fully revolving for 364-day periods with an initial term to June 2004 and a provision for extension at the mutual agreement of the Company and the lenders. If not extended, the facility converts to a non-revolving loan with a term of two years. The full amount of the outstanding principal would be repayable at the end of year two following the initiation of the term period. The facility provides that the borrowings may be made by way of operating advances, prime loans, bankers' acceptances, US base rate loans or US dollar LIBOR advances, which bear interest at the bank's prime rates or at money market rates plus applicable margins. During the year, the Company repaid and cancelled a $500 million acquisition term credit facility. The weighted average interest rate of bank credit facilities outstanding at December 31, 2003, was 2.32% (2002 - 3.37%). In addition to the outstanding debt, letters of credit aggregating $69 million have been issued. MEDIUM-TERM NOTES In August 2003, the Company filed a short form shelf prospectus that allows for the issue of up to $1 billion of medium term notes in Canada until September 2005. If issued, these securities will bear interest as determined at the date of issuance. The Company has $250 million of unsecured debentures outstanding from a previous medium-term note program. SENIOR UNSECURED NOTES The final principal repayment on the 6.95% senior unsecured notes was made September 30, 2003. The 6.42% senior unsecured notes are due in full May 27, 2004. In May 2003, the Company prepaid the US$50 million 6.50% senior unsecured notes due May 1, 2008. The adjustable rate senior unsecured notes bear interest at 6.54% increasing to 6.64% under certain circumstances, and have annual principal repayments of US$31 million commencing on May 27, 2007, through May 27, 2009. These debt instruments contain covenants pertaining to the Company's net worth, certain financial ratios and the ability to grant security. On July 1, 2002, as part of the Rio Alto acquisition, the Company assumed US$125 million of senior unsecured notes maturing December 19, 2005, bearing interest at 7.69%. Through a currency swap, the interest and principal repayment amounts are fixed at 7.30% and $194 million, respectively (note 10). US DOLLAR DEBT SECURITIES In May 2003, the Company filed a short form prospectus that allows for the issue of up to US$2 billion of debt securities in the United States until June 2005. If issued, these securities will bear interest as determined at the date of issuance. On September 16, 2002, the Company issued US$350 million of US dollar debt securities maturing October 1, 2012, bearing interest at 5.45% and US$350.0 million of US dollar debt securities maturing June 30, 2033, bearing interest at 6.45%. Proceeds from the securities issued were used to repay bankers' acceptances under the Company's bank credit facilities. Subsequently, the Company entered into interest rate swap contracts that convert the fixed rate interest coupon into a floating interest rate on the securities due October 1, 2012 (note 10). On January 23, 2002, the Company issued US$400 million of US dollar debt securities, maturing January 15, 2032, bearing interest at 7.20%. Proceeds from the securities issued were used to repay bankers' acceptances under the Company's bank credit facilities. Subsequently, the Company entered into interest rate swap contracts that convert the fixed rate interest coupon into a floating interest rate for a portion of the term (note 10). OBLIGATIONS UNDER CAPITAL LEASES The obligations under capital leases bear interest at an average interest rate of 6.89% and are secured by the related assets. REQUIRED DEBT REPAYMENTS Required debt repayments are as follows: YEAR REPAYMENT ================================================================================ 2004 $ 184 - -------------------------------------------------------------------------------- 2005 $ 194 - -------------------------------------------------------------------------------- 2006 $ -- - -------------------------------------------------------------------------------- 2007 $ 165 - -------------------------------------------------------------------------------- 2008 $ 40 - -------------------------------------------------------------------------------- Thereafter $ 1,978 ================================================================================ No debt repayments are reflected for the bank credit facilities due to the extendable nature of the facilities. 68 CANADIAN NATURAL
4. DEFERRED CREDITS 2003 2002 ============================================================================================== Future site restoration $ 447 $ 440 - ---------------------------------------------------------------------------------------------- Stock-based compensation 41 -- ============================================================================================== $ 488 $ 440 ==============================================================================================
FUTURE SITE RESTORATION At December 31, 2003, the Company's total estimated future site restoration costs were $2,281 million (2002 - $1,986 million, 2001 - $1,081 million). These costs are accrued over the life of the Company's proved reserves. Effective January 1, 2004, the Company will adopt the CICA's new accounting standard for asset retirement obligations (note 16).
2003 2002 ============================================================================================== Future site restoration - ---------------------------------------------------------------------------------------------- Balance - beginning of year $ 440 $ 194 - ---------------------------------------------------------------------------------------------- Future site restoration provision 104 67 - ---------------------------------------------------------------------------------------------- Current year expenditures (40) (34) - ---------------------------------------------------------------------------------------------- Acquisitions and dispositions -- 211 - ---------------------------------------------------------------------------------------------- Foreign exchange (57) 2 ============================================================================================== Balance - end of year $ 447 $ 440 ==============================================================================================
STOCK-BASED COMPENSATION In June 2003, the Company modified its Option Plan (note 7), resulting in the recognition of a liability for the expected cash settlements under the Option Plan. The current portion represents the amount of the liability that may be realized within the next 12 month period if all vested options are surrendered for cash settlement.
2003 ============================================================================================== Stock-based compensation - ---------------------------------------------------------------------------------------------- Balance - beginning of year $ -- - ---------------------------------------------------------------------------------------------- Stock-based compensation provision 200 - ---------------------------------------------------------------------------------------------- Current year payment for options surrendered (31) - ---------------------------------------------------------------------------------------------- Transferred to common shares (8) - ---------------------------------------------------------------------------------------------- Capitalized with respect to Horizon Project 10 ============================================================================================== Balance - end of year 171 - ---------------------------------------------------------------------------------------------- Less: current portion of stock-based compensation 130 ============================================================================================== $ 41 ==============================================================================================
5. TAXES TAXES OTHER THAN INCOME TAX 2003 2002 2001 ============================================================================================== Current petroleum revenue tax $ 106 $ 41 $ 59 - ---------------------------------------------------------------------------------------------- Deferred petroleum revenue tax (9) 10 -- - ---------------------------------------------------------------------------------------------- Provincial capital taxes and surcharges 10 11 9 - ---------------------------------------------------------------------------------------------- Other -- 1 1 ============================================================================================== $ 107 $ 63 $ 69 ============================================================================================== INCOME TAX The provision for income tax is as follows: 2003 2002 2001 ============================================================================================== Current income tax expense - ---------------------------------------------------------------------------------------------- Current income tax - North America $ 43 $ -- $ -- - ---------------------------------------------------------------------------------------------- Large Corporations Tax - North America 16 21 15 - ---------------------------------------------------------------------------------------------- Current income tax - North Sea 23 (19) 62 - ---------------------------------------------------------------------------------------------- Current income tax - Offshore West Africa 10 6 -- ============================================================================================== 92 8 77 Future income tax expense 339 400 283 ============================================================================================== Income tax $ 431 $ 408 $ 360 ==============================================================================================
69 ANNUAL REPORT 2003 Notes to the consolidated financial statements The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows:
2003 2002 2001 ============================================================================================== Canadian statutory income tax rate 41.1% 42.4% 42.8% ============================================================================================== Income tax provision at statutory rate $ 794 $ 444 $ 464 - ---------------------------------------------------------------------------------------------- Effect on income taxes of: - ---------------------------------------------------------------------------------------------- Non-deductible portion of Canadian crown payments 285 211 201 - ---------------------------------------------------------------------------------------------- Canadian resource allowance (281) (243) (219) - ---------------------------------------------------------------------------------------------- Large Corporations Tax 16 21 15 - ---------------------------------------------------------------------------------------------- Deductible UK petroleum revenue tax (40) (22) (25) - ---------------------------------------------------------------------------------------------- Foreign tax rate differentials 20 (1) (19) - ---------------------------------------------------------------------------------------------- Federal income tax rate reductions (247) -- -- - ---------------------------------------------------------------------------------------------- Provincial income tax rate reductions (31) (21) (63) - ---------------------------------------------------------------------------------------------- UK income tax rate increase -- 34 -- - ---------------------------------------------------------------------------------------------- Non-taxable portion of foreign exchange (99) (22) 21 - ---------------------------------------------------------------------------------------------- Other 14 7 (15) ============================================================================================== Income tax $ 431 $ 408 $ 360 ==============================================================================================
The following table summarizes the temporary differences that give rise to the future income tax liability:
2003 2002 ============================================================================================== Future income tax liabilities - ---------------------------------------------------------------------------------------------- Property, plant and equipment $ 2,701 $ 2,656 - ---------------------------------------------------------------------------------------------- Timing of partnership items 1,095 737 - ---------------------------------------------------------------------------------------------- Foreign exchange gain on long-term debt 90 -- - ---------------------------------------------------------------------------------------------- Other 14 14 - ---------------------------------------------------------------------------------------------- Future income tax assets - ---------------------------------------------------------------------------------------------- Future site restoration (185) (161) - ---------------------------------------------------------------------------------------------- Attributed Canadian Royalty Income (58) (54) - ---------------------------------------------------------------------------------------------- Stock-based compensation (56) -- - ---------------------------------------------------------------------------------------------- Deferred petroleum revenue tax (13) (4) ============================================================================================== Future income tax liability $ 3,588 $ 3,188 ==============================================================================================
A significant portion of the Company's North American taxable income is generated by partnerships. Income taxes are incurred on the partnerships' taxable income in the year following their inclusion in the Company's consolidated net earnings. During 2003, the Government of Alberta passed legislation to reduce its corporate income tax rate by 0.5% effective April 1, 2003. Also during 2003, the Canadian federal government passed legislation to change the taxation of resource income. The legislation reduces the corporate income tax rate on resource income from 28% to 21% over five years beginning January 1, 2003. Over the same period, the deduction for resource allowance is phased out and a deduction for actual crown royalties paid is phased in. The Company's future income tax liability was reduced by $31 million with respect to the Alberta corporate income tax rate reduction and by $247 million with respect to the Federal resource income tax rate changes. 6. PREFERRED SECURITIES The US$80 million preferred securities are in the form of 8.30% subordinated notes. Principal repayments of US$27 million are required annually commencing June 25, 2009. The securities may be prepaid at the option of the Company at any time. The prepaid amount is subject to certain adjustments to compensate holders for any potential loss of return over the original life of the securities, based on market conditions at that time. The notes are subordinated to the long-term debt of the Company and contain, among other things, certain financial covenants restricting the granting of security for new borrowings and the maintenance of specified financial ratios. The Company has the unrestricted right to pay dividends, principal and principal prepayment amounts by delivering common shares to the Trustee of the preferred securities. Accordingly, the preferred securities are classified as shareholders' equity in the consolidated balance sheets. Dividend payments, net of tax, are charged directly to retained earnings. The semi-annual dividend payments may be deferred at the option of the Company for up to two consecutive periods, with a maximum of eight deferral periods over the life of the securities. 70 CANADIAN NATURAL 7. SHARE CAPITAL AUTHORIZED 200,000 Class 1 preferred shares with a stated value of $10.00 each. Unlimited number of common shares without par value. ISSUED
2003 2002 - -------------------------------------------------------------------------------------------------------------- NUMBER OF NUMBER OF SHARES SHARES COMMON SHARES (THOUSANDS) AMOUNT (THOUSANDS) AMOUNT ============================================================================================================== Balance - beginning of year 133,776 $ 2,304 121,201 $ 1,698 - -------------------------------------------------------------------------------------------------------------- Issued upon exercise of stock options 2,690 89 2,523 82 - -------------------------------------------------------------------------------------------------------------- Previously recognized liability on stock options exercised for common shares -- 8 -- -- - -------------------------------------------------------------------------------------------------------------- Purchase of common shares under Normal Course Issuer Bid (2,735) (48) -- -- - -------------------------------------------------------------------------------------------------------------- Issued upon acquisition of Rio Alto -- -- 10,008 522 - -------------------------------------------------------------------------------------------------------------- Issue of flow-through shares, net of tax -- -- 60 2 - -------------------------------------------------------------------------------------------------------------- Cancellation of common shares -- -- (16) -- ============================================================================================================== Balance - end of year 133,731 $ 2,353 133,776 $ 2,304 ==============================================================================================================
During 2002, the Company issued 10,008,218 common shares at an attributed value of $522 million as part of the consideration to acquire Rio Alto (note 13). During 2002, the Company issued 60,000 flow-through common shares to a director of the Company at a price of $39.00 per common share, for total proceeds of $2 million. The value of the common shares was determined as the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the allotment. During 2002, 16,288 common shares were returned to treasury and cancelled on the expiry of the conversion period for exchanging shares of companies previously acquired for common shares of the Company. NORMAL COURSE ISSUER BID During 2003, the Company purchased 2,734,800 common shares at an average price of $52.51 per common share for a total cost of $144 million. The excess cost over book value of the common shares purchased was applied to reduce retained earnings. In January 2004, the Company renewed its Normal Course Issuer Bid, allowing the Company to purchase up to 6,690,385 common shares or 5% of the Company's outstanding common shares on the date of announcement, during the 12-month period beginning January 24, 2004 and ending January 23, 2005. As at February 19, 2004, the Company had not purchased any additional shares under the renewed Normal Course Issuer Bid. DIVIDEND POLICY The Company pays regular quarterly dividends in January, April, July and October of each year. On February 19, 2004, the Board of Directors set the Company's regular quarterly dividend at $0.20 per common share (2003 - $0.15 per common share, 2002 - $0.125 per common share, 2001 - $0.10 per common share) commencing with the April 1, 2004 payment. STOCK OPTIONS The Company's Option Plan provides for granting of stock options to directors, officers and employees. Stock options granted under the Option Plan have a maximum term of six years to expiry and vest equally over a five-year period starting on the first anniversary date of the grant. The exercise price of each stock option granted is determined as the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the grant. Each stock option granted permits the holder to purchase one common share of the Company at the stated exercise price. MODIFICATION OF STOCK OPTION PLAN In June 2003, the Company approved a modification to its Option Plan providing the stock option holder the right to elect to receive a cash payment equal to the difference between the exercise price of the stock option and the market price of the Company's common shares on the date of surrender, multiplied by the number of common shares covered by the stock options surrendered, in lieu of receiving common shares. The modification to the Option Plan was accounted for prospectively and for the year ended December 31, 2003, the Company recorded compensation expense of $200 million. As at December 31, 2003, the total liability for expected cash settlements under the Option Plan is $171 million, of which $130 million is included as a current liability. During the year ended December 31, 2003, cash payments of $31 million were made for 1,337,398 stock options surrendered. 71 ANNUAL REPORT 2003 Notes to the consolidated financial statements Prior to the modification, the Company disclosed pro-forma measures of net earnings attributable to common shareholders and net earnings attributable to common shareholders per common share as if stock options had been recognized as compensation expense estimated on the date of grant using the Black-Scholes option pricing model. As stock-based compensation is now reflected in the consolidated statement of earnings, the pro-forma disclosures are no longer required. The following table summarizes information relating to stock options outstanding at December 31, 2003 and 2002:
2003 2002 - ------------------------------------------------------------------------------------------------------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE STOCK OPTIONS EXERCISE STOCK OPTIONS EXERCISE (THOUSANDS) PRICE (THOUSANDS) PRICE =================================================================================================================== Outstanding - beginning of year 12,882 $ 37.13 12,051 $ 34.77 - ------------------------------------------------------------------------------------------------------------------- Granted 668 $ 52.31 3,845 $ 41.88 - ------------------------------------------------------------------------------------------------------------------- Exercised for common shares (2,690) $ 33.14 (2,523) $ 32.54 - ------------------------------------------------------------------------------------------------------------------- Surrendered for cash settlement (1,337) $ 34.71 -- $ -- - ------------------------------------------------------------------------------------------------------------------- Forfeited (629) $ 42.78 (491) $ 40.03 =================================================================================================================== Outstanding - end of year 8,894 $ 39.44 12,882 $ 37.13 =================================================================================================================== Exercisable - end of year 2,323 $ 34.65 3,508 $ 32.53 ===================================================================================================================
The range of exercise prices of stock options outstanding and exercisable at December 31, 2003 is as follows:
STOCK OPTIONS OUTSTANDING STOCK OPTIONS EXERCISABLE - ------------------------------------------------------------------------------------------------------------------- WEIGHTED STOCK AVERAGE WEIGHTED STOCK WEIGHTED OPTIONS REMAINING AVERAGE OPTIONS AVERAGE OUTSTANDING TERM EXERCISE EXERCISABLE EXERCISE RANGE OF EXERCISE PRICES (thousands) (years) PRICE (thousands) PRICE =================================================================================================================== $19.90 to $24.99 456 0.8 $ 22.01 427 $ 21.99 - ------------------------------------------------------------------------------------------------------------------- $25.00 to $29.99 268 0.3 $ 27.25 236 $ 27.32 - ------------------------------------------------------------------------------------------------------------------- $30.00 to $34.99 1,561 2.0 $ 33.65 554 $ 33.66 - ------------------------------------------------------------------------------------------------------------------- $35.00 to $39.99 3,520 3.5 $ 39.04 635 $ 39.23 - ------------------------------------------------------------------------------------------------------------------- $40.00 to $44.99 1,154 3.5 $ 42.92 271 $ 43.59 - ------------------------------------------------------------------------------------------------------------------- $45.00 to $49.99 1,431 4.3 $ 46.71 200 $ 46.48 - ------------------------------------------------------------------------------------------------------------------- $50.00 to $54.66 504 5.7 $ 53.74 -- $ -- =================================================================================================================== 8,894 3.2 $ 39.44 2,323 $ 34.65 ===================================================================================================================
8. FOREIGN CURRENCY TRANSLATION ADJUSTMENT The foreign currency translation adjustment represents the unrealized gain (loss) on the Company's net investment in self-sustaining foreign operations. Effective July 1, 2002, the Company designated certain US dollar denominated debt as a hedge against its net investment in US dollar-based self-sustaining foreign operations. Accordingly, translation gains and losses on this US dollar denominated debt are included in the foreign currency translation adjustment.
2003 2002 =================================================================================================================== Balance - beginning of year $ 24 $ 73 - ------------------------------------------------------------------------------------------------------------------- Unrealized (loss) gain on translation of net investment (108) (12) - ------------------------------------------------------------------------------------------------------------------- Hedge of net investment with US dollar denominated debt, net of tax 101 (37) =================================================================================================================== Balance - end of year $ 17 $ 24 ===================================================================================================================
72 CANADIAN NATURAL 9. NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS PER COMMON SHARE The following table provides a reconciliation between basic and diluted amounts per common share:
(thousands of shares) 2003 2002 2001 =================================================================================================================== Weighted average common shares outstanding - basic 134,235 127,883 121,300 - ------------------------------------------------------------------------------------------------------------------- Effect of dilutive stock options (1) 1,222 2,744 2,594 - ------------------------------------------------------------------------------------------------------------------- Assumed settlement of preferred securities with common shares 1,954 2,681 2,883 =================================================================================================================== Weighted average common shares outstanding - diluted 137,411 133,308 126,777 =================================================================================================================== Net earnings attributable to common shareholders $ 1,407 $ 570 $ 642 - ------------------------------------------------------------------------------------------------------------------- Dividend on preferred securities, net of tax 5 6 6 - ------------------------------------------------------------------------------------------------------------------- Revaluation of preferred securities, net of tax (18) (1) 8 =================================================================================================================== Diluted net earnings attributable to common shareholders $ 1,394 $ 575 $ 656 =================================================================================================================== Net earnings attributable to common shareholders per common share Basic $ 10.48 $ 4.46 $ 5.30 - ------------------------------------------------------------------------------------------------------------------- Diluted $ 10.14 $ 4.31 $ 5.17 ===================================================================================================================
(1) The modification of the Option Plan described in note 7 results in a liability and expense for all outstanding stock options. As such, the potential common shares associated with the stock options are not included in diluted earnings per share effective from June 2003, the date of the modification. For the year ended December 31, 2002, 319,916 stock options with a weighted average exercise price of $48.33 (2001 - 692,790 stock options with a weighted average exercise price of $45.78), were excluded from the calculation as their effect on per common share amounts was anti-dilutive. 10. FINANCIAL INSTRUMENTS FINANCIAL CONTRACTS The Company's financial instruments recognized in the consolidated balance sheets consist of cash, accounts receivable, accounts payable, accrued liabilities and long-term debt. The estimated fair values of financial instruments have been determined based on the Company's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The carrying value of cash, accounts receivable, accounts payable, accrued liabilities and long-term debt with variable interest rates approximate their fair value. The estimated fair values of other financial instruments are as follows:
2003 2002 - ------------------------------------------------------------------------------------------------------------------- CARRYING VALUE FAIR VALUE CARRYING VALUE FAIR VALUE ASSET (LIABILITY) - ------------------------------------------------------------------------------------------------------------------- Derivative financial instruments $ -- $ 16 $ -- $ 56 - ------------------------------------------------------------------------------------------------------------------- Fixed rate notes $ (2,664) $ (2,880) $ (3,259) $ (3,573) ===================================================================================================================
73 ANNUAL REPORT 2003 Notes to the Consolidated Financial Statements The Company uses certain derivative financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for trading or other speculative purposes. The following summarizes transactions outstanding as at December 31, 2003:
REMAINING TERM VOLUME AVERAGE PRICE INDEX ================================================================================================================= OIL - ----------------------------------------------------------------------------------------------------------------- Brent differential swaps Jan. 2004 - Dec. 2004 40,000 bbl/d US$1.22 WTI/Dated Brent - ----------------------------------------------------------------------------------------------------------------- Oil price collars Jan. 2004 - Mar. 2004 123,000 bbl/d US$25.24 - US$30.87 WTI - ----------------------------------------------------------------------------------------------------------------- Apr. 2004 - Jun. 2004 120,000 bbl/d US$25.06 - US$29.84 WTI - ----------------------------------------------------------------------------------------------------------------- Jul. 2004 - Sep. 2004 120,000 bbl/d US$25.63 - US$30.41 WTI - ----------------------------------------------------------------------------------------------------------------- Oct. 2004 - Dec. 2004 60,000 bbl/d US$25.50 - US$30.32 WTI - ----------------------------------------------------------------------------------------------------------------- NATURAL GAS - ----------------------------------------------------------------------------------------------------------------- AECO collars Jan. 2004 - Mar. 2004 300,000 GJ/d C$6.00 - C$10.14 AECO ================================================================================================================= AMOUNT AVERAGE EXCHANGE RATE REMAINING TERM ($ millions) (US$/C$) ================================================================================================================= FOREIGN CURRENCY - ----------------------------------------------------------------------------------------------------------------- Currency collars - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Aug. 2004 US$20/month 1.51 - 1.59 - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Sep. 2004 US$5/month 1.52 - 1.59 - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Dec. 2004 US$3/month 1.45 - 1.54 - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Aug. 2005 US$10/month 1.37 - 1.49 ================================================================================================================= EXCHANGE INTEREST INTEREST AMOUNT RATE RATE RATE REMAINING TERM ($ millions) (US$/C$) (US$) (C$) ================================================================================================================= Currency swap Jan. 2004 - Dec. 2005 US$125 1.55 7.69% 7.30% ================================================================================================================= AMOUNT REMAINING TERM ($ millions) FIXED RATE FLOATING RATE ================================================================================================================= INTEREST RATE - ----------------------------------------------------------------------------------------------------------------- Swaps - fixed to floating Jan. 2004 - Jul. 2004 US$200 6.70% LIBOR + 2.09% - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Jul. 2006 US$200 6.70% LIBOR + 1.58% - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Jan. 2005 US$200 7.20% LIBOR + 3.00% - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Jan. 2007 US$200 7.20% LIBOR + 2.23% - ----------------------------------------------------------------------------------------------------------------- Jan. 2004 - Oct. 2012 US$350 5.45% LIBOR + 0.81% - ----------------------------------------------------------------------------------------------------------------- Swaps - floating to fixed Jan. 2004 - Mar. 2007 C$16 7.36% CDOR =================================================================================================================
CREDIT RISK Accounts receivable are mainly with customers in the oil and natural gas industry and are subject to normal industry credit risks. The Company minimizes this risk by entering into sales contracts with only highly rated entities. In addition, the Company reviews its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. The Company is also exposed to certain losses in the event of non-performance by counterparties to derivative financial instruments; however, the Company minimizes this credit risk by entering into agreements with only highly rated financial institutions. 11. COMMITMENTS The Company has committed to certain payments as follows:
2004 2005 2006 2007 2008 THEREAFTER ================================================================================================================= Natural gas transportation $ 180 $ 169 $ 143 $ 103 $ 77 $ 194 - ----------------------------------------------------------------------------------------------------------------- Oil transportation and pipeline $ 15 $ 13 $ 13 $ 15 $ 13 $ 167 - ----------------------------------------------------------------------------------------------------------------- Offshore equipment operating lease $ 169 $ 129 $ 75 $ 75 $ 75 $ 367 - ----------------------------------------------------------------------------------------------------------------- Electricity $ 28 $ 27 $ 27 $ -- $ -- $ -- - ----------------------------------------------------------------------------------------------------------------- Office lease $ 20 $ 20 $ 19 $ 17 $ 16 $ 50 - ----------------------------------------------------------------------------------------------------------------- Processing $ 6 $ 5 $ 2 $ -- $ -- $ -- =================================================================================================================
74 CANADIAN NATURAL 12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Changes in non-cash working capital were as follows: 2003 2002 2001 ================================================================================ Decrease (increase) in non-cash working capital - -------------------------------------------------------------------------------- Accounts receivable and other $ 35 $(164) $ 80 - -------------------------------------------------------------------------------- Accounts payable 125 (145) (60) - -------------------------------------------------------------------------------- Accrued liabilities 122 154 (107) ================================================================================ Net change in non-cash working capital $ 282 $(155) $ (87) ================================================================================ Relating to: - -------------------------------------------------------------------------------- Operating activities $ (48) $(157) $ (42) - -------------------------------------------------------------------------------- Financing activities (11) 27 7 - -------------------------------------------------------------------------------- Investing activities 341 (25) (52) ================================================================================ $ 282 $(155) $ (87) ================================================================================ Other cash flow information: 2003 2002 2001 ================================================================================ Interest paid $ 178 $ 132 $ 127 - -------------------------------------------------------------------------------- Taxes paid $ 51 $ 160 $ 161 ================================================================================ 13. BUSINESS COMBINATION RIO ALTO EXPLORATION LTD. In July 2002, the Company paid cash of $850 million and issued 10,008,218 common shares with an attributed value of $522 million to acquire all of the issued and outstanding common shares of Rio Alto Exploration Ltd. ("Rio Alto") by way of a plan of arrangement (the "Plan of Arrangement"). Rio Alto was engaged in the exploration for and production of oil and natural gas in western Canada and, through wholly owned subsidiaries, in South America. Under the Plan of Arrangement, the subsidiaries of Rio Alto that held its South American properties were sold to a new company, Rio Alto Resources International Inc. ("Rio Alto International"), and each shareholder of Rio Alto received one common share of Rio Alto International for each Rio Alto common share held. The acquisition was accounted for based on the purchase method. Results of Rio Alto are consolidated with the results of the Company since the date of acquisition. The allocation of the purchase price to assets acquired and liabilities assumed based on their fair values is set out in the following table: July 1, 2002 ================================================================================ Purchase price: - -------------------------------------------------------------------------------- Cash consideration $ 850 - -------------------------------------------------------------------------------- Share consideration 522 - -------------------------------------------------------------------------------- Cash acquired (7) - -------------------------------------------------------------------------------- Non-cash working capital deficit assumed 92 - -------------------------------------------------------------------------------- Long-term debt assumed 936 ================================================================================ Total purchase price $ 2,393 ================================================================================ Purchase price allocated as follows: - -------------------------------------------------------------------------------- Property, plant and equipment $ 3,412 - -------------------------------------------------------------------------------- Future site restoration (44) ================================================================================ Future income tax (975) ================================================================================ $ 2,393 75 ANNUAL REPORT 2003 Notes to the consolidated financial statements 14. SEGMENTED INFORMATION The Company's oil and natural gas activities are conducted in three geographic segments: North America, the North Sea and Offshore West Africa. These activities relate to the exploration, development, production and marketing of oil, natural gas liquids and natural gas. The Company's Horizon Project has been classified as a separate segment. As the bitumen will be recovered through mining operations, this project constitutes a distinct segment from oil and natural gas activities. There are currently no revenues for this project and all directly related expenditures have been capitalized. Midstream activities include the Company's pipeline operations and an electricity co-generation system.
OIL AND NATURAL GAS - ------------------------------------------------------------------------------------------------------------------- NORTH AMERICA NORTH SEA - ------------------------------------------------------------------------------------------------------------------- 2003 2002 2001 2003 2002 2001 =================================================================================================================== REVENUE $ 4,829 $ 3,610 $ 3,163 $ 961 $ 612 $ 534 - ------------------------------------------------------------------------------------------------------------------- Less: royalties (867) (564) (551) 1 (33) (28) =================================================================================================================== 3,962 3,046 2,612 962 579 506 =================================================================================================================== EXPENSES - ------------------------------------------------------------------------------------------------------------------- Production 845 656 597 314 229 123 - ------------------------------------------------------------------------------------------------------------------- Transportation 263 273 166 30 20 11 - ------------------------------------------------------------------------------------------------------------------- Depletion, depreciation and amortization 1,248 1,033 746 268 193 129 - ------------------------------------------------------------------------------------------------------------------- Administration 87 61 37 -- -- 1 - ------------------------------------------------------------------------------------------------------------------- Stock-based compensation 190 -- -- 7 -- -- - ------------------------------------------------------------------------------------------------------------------- Interest 153 156 130 4 3 8 - ------------------------------------------------------------------------------------------------------------------- Foreign exchange (gain) loss (345) (52) 60 39 21 2 - ------------------------------------------------------------------------------------------------------------------- Loss on sale of United States assets -- -- 24 -- -- -- =================================================================================================================== 2,441 2,127 1,760 662 466 274 =================================================================================================================== EARNINGS BEFORE TAXES 1,521 919 852 300 113 232 - ------------------------------------------------------------------------------------------------------------------- Taxes other than income tax 10 11 9 97 51 59 - ------------------------------------------------------------------------------------------------------------------- Current income tax 59 21 15 23 (19) 62 - ------------------------------------------------------------------------------------------------------------------- Future income tax 246 322 290 59 82 (9) =================================================================================================================== NET EARNINGS 1,206 565 538 121 (1) 120 - ------------------------------------------------------------------------------------------------------------------- Dividend on preferred securities, net of tax (5) (6) (6) -- -- -- - ------------------------------------------------------------------------------------------------------------------- Revaluation of preferred securities, net of tax 18 1 (8) -- -- -- =================================================================================================================== NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 1,219 $ 560 $ 524 $ 121 $ (1) $ 120 ===================================================================================================================
(1) Eliminates internal transportation and electricity charges. CAPITAL EXPENDITURES
2003 - -------------------------------------------------------------------------------------------------------------------- CASH NON-CASH CAPITAL FAIR VALUE CAPITALIZED CONSIDERATION CONSIDERATION EXPENDITURES ADJUSTMENTS (1) COSTS ==================================================================================================================== Oil and natural gas - -------------------------------------------------------------------------------------------------------------------- North America - business combination $ -- $ -- $ -- $ -- $ -- - -------------------------------------------------------------------------------------------------------------------- North America - oil and natural gas 1,769 -- 1,769 -- 1,769 - -------------------------------------------------------------------------------------------------------------------- North Sea 338 -- 338 25 363 - -------------------------------------------------------------------------------------------------------------------- Offshore West Africa 176 -- 176 -- 176 ==================================================================================================================== 2,283 -- 2,283 25 2,308 - -------------------------------------------------------------------------------------------------------------------- Horizon Project 152 -- 152 -- 152 - -------------------------------------------------------------------------------------------------------------------- Midstream 11 -- 11 -- 11 - -------------------------------------------------------------------------------------------------------------------- Abandonments (2) 40 -- 40 -- 40 - -------------------------------------------------------------------------------------------------------------------- Head office 20 -- 20 -- 20 ==================================================================================================================== $ 2,506 $ -- $ 2,506 $ 25 $ 2,531 ====================================================================================================================
(1) Future income tax adjustments on non tax base assets and other fair value adjustments. (2) Abandonment expenditures were incurred in the following segments; $30 million North America, $1 million North Sea and $9 million Offshore West Africa (2002 - $ 32 million North America, $9 million North Sea and $2 million Offshore West Africa). 76 CANADIAN NATURAL
INTERSEGMENT MIDSTREAM ELIMINATIONS (1) TOTAL - ------------------------------------------------------------------------------------------------------------------------------------ OFFSHORE WEST AFRICA - ------------------------------------------------------------------------------------------------------------------------------------ 2003 2002 2001 2003 2002 2001 2003 2002 2001 2003 2002 2001 ==================================================================================================================================== REVENUE $ 156 $ 102 $ 42 $ 61 $ 52 $ 27 $ (35) $ (34) $ (9) $ 5,972 $ 4,342 $ 3,757 - ------------------------------------------------------------------------------------------------------------------------------------ Less: royalties (6) (3) (1) -- -- -- -- -- -- (872) (600) (580) ==================================================================================================================================== 150 99 41 61 52 27 (35) (34) (9) 5,100 3,742 3,177 ==================================================================================================================================== EXPENSES - ------------------------------------------------------------------------------------------------------------------------------------ Production 38 35 27 15 14 11 (3) (3) (2) 1,209 931 756 - ------------------------------------------------------------------------------------------------------------------------------------ Transportation 1 -- -- -- -- -- (32) (31) (7) 262 262 170 - ------------------------------------------------------------------------------------------------------------------------------------ Depletion, depreciation and amortization 42 80 24 7 8 4 -- -- -- 1,565 1,314 903 - ------------------------------------------------------------------------------------------------------------------------------------ Administration -- -- -- -- -- -- -- -- -- 87 61 38 - ------------------------------------------------------------------------------------------------------------------------------------ Stock-based compensation 3 -- -- -- -- -- -- -- -- 200 -- -- - ------------------------------------------------------------------------------------------------------------------------------------ Interest -- -- -- -- -- -- -- -- -- 157 159 138 - ------------------------------------------------------------------------------------------------------------------------------------ Foreign exchange (gain) loss (6) -- 1 -- -- -- -- -- -- (312) (31) 63 - ------------------------------------------------------------------------------------------------------------------------------------ Loss on sale of United States assets -- -- -- -- -- -- -- -- -- -- -- 24 ==================================================================================================================================== 78 115 52 22 22 15 (35) (34) (9) 3,168 2,696 2,092 ==================================================================================================================================== EARNINGS BEFORE TAXES 72 (16) (11) 39 30 12 -- -- -- 1,932 1,046 1,085 - ------------------------------------------------------------------------------------------------------------------------------------ Taxes other than income tax -- 1 1 -- -- -- -- -- -- 107 63 69 - ------------------------------------------------------------------------------------------------------------------------------------ Current income tax 10 6 -- -- -- -- -- -- -- 92 8 77 - ------------------------------------------------------------------------------------------------------------------------------------ Future income tax 18 (17) (3) 16 13 5 -- -- -- 339 400 283 ==================================================================================================================================== NET EARNINGS 44 (6) (9) 23 17 7 -- -- -- 1,394 575 656 - ------------------------------------------------------------------------------------------------------------------------------------ Dividend on preferred securities, net of tax -- -- -- -- -- -- -- (5) (6) (6) - ------------------------------------------------------------------------------------------------------------------------------------ Revaluation of preferred securities, net of tax -- -- -- -- -- -- -- -- -- 18 1 (8) ==================================================================================================================================== NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 44 $ (6) $ (9) $ 23 $ 17 $ 7 $ -- $ -- $ -- $ 1,407 $ 570 $ 642 ====================================================================================================================================
2002 - -------------------------------------------------------------------------------------------------------------------- CASH NON-CASH CAPITAL FAIR VALUE CAPITALIZED CONSIDERATION CONSIDERATION EXPENDITURES ADJUSTMENTS (1) COSTS ==================================================================================================================== Oil and natural gas - -------------------------------------------------------------------------------------------------------------------- North America - business combination $ 844 $ 1,550 $ 2,394 $ 1,019 $ 3,413 - -------------------------------------------------------------------------------------------------------------------- North America - oil and natural gas 1,026 -- 1,026 -- 1,026 - -------------------------------------------------------------------------------------------------------------------- North Sea 323 -- 323 232 555 - -------------------------------------------------------------------------------------------------------------------- Offshore West Africa 186 -- 186 -- 186 ==================================================================================================================== 2,379 1,550 3,929 1,251 5,180 - -------------------------------------------------------------------------------------------------------------------- Horizon Project 68 -- 68 -- 68 - -------------------------------------------------------------------------------------------------------------------- Midstream 20 -- 20 -- 20 - -------------------------------------------------------------------------------------------------------------------- Abandonments (2) 43 -- 43 -- 43 - -------------------------------------------------------------------------------------------------------------------- Head office 10 -- 10 -- 10 ==================================================================================================================== $ 2,520 $ 1,550 $ 4,070 $ 1,251 $ 5,321 ====================================================================================================================
77 ANNUAL REPORT 2003 Notes to the consolidated financial statements
SEGMENTED PROPERTY, PLANT AND EQUIPMENT, NET 2003 2002 ========================================================================================================== Oil and natural gas - ---------------------------------------------------------------------------------------------------------- North America $ 10,841 $ 10,252 - ---------------------------------------------------------------------------------------------------------- North Sea 1,157 1,277 - ---------------------------------------------------------------------------------------------------------- Offshore West Africa 651 518 - ---------------------------------------------------------------------------------------------------------- Horizon Project 381 229 - ---------------------------------------------------------------------------------------------------------- Midstream 200 196 - ---------------------------------------------------------------------------------------------------------- Head office 39 28 ========================================================================================================== $ 13,269 $ 12,500 ========================================================================================================== SEGMENTED ASSETS 2003 2002 ========================================================================================================== Oil and natural gas - ---------------------------------------------------------------------------------------------------------- North America $ 11,582 $ 10,917 - ---------------------------------------------------------------------------------------------------------- North Sea 1,282 1,427 - ---------------------------------------------------------------------------------------------------------- Offshore West Africa 687 549 - ---------------------------------------------------------------------------------------------------------- Horizon Project 381 229 - ---------------------------------------------------------------------------------------------------------- Midstream 227 209 - ---------------------------------------------------------------------------------------------------------- Head office 39 28 ========================================================================================================== $ 14,198 $ 13,359 ==========================================================================================================
15. SUBSEQUENT EVENT ACQUISITION OF PETROVERA PARTNERSHIP On February 18, 2004, the Company acquired certain resource properties located in East Central Alberta and Saskatchewan (collectively known as the Petrovera Partnership) for aggregate consideration of $701 million. In a separate transaction, the Company sold specific resource properties in the Petrovera Partnership, representing approximately one third of the total acquisition, to another independent producer for proceeds of $234 million, resulting in a net cost of $467 million for the retained properties. The net production from the working interests retained by the Company is approximately 27,500 barrels per day of heavy oil and nine million cubic feet per day of natural gas together with volumes associated with royalty interests of 1,200 barrels per day of heavy oil and two million cubic feet per day of natural gas. 16. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Company's consolidated financial statements have been prepared in accordance with generally accepted accounting principles in Canada ("Canadian GAAP"). These principles conform in all material respects with those in the United States ("US GAAP") except for those noted below. Differences arising from US GAAP disclosure requirements are not addressed. The application of US GAAP would have the following effects on consolidated net earnings as reported:
(millions of Canadian dollars, except per common share amounts) Notes 2003 2002 2001 ========================================================================================================== Net earnings - Canadian GAAP $ 1,394 $ 57 $ 656 - ---------------------------------------------------------------------------------------------------------- Adjustments, net of tax - ---------------------------------------------------------------------------------------------------------- Depletion (A,D) 37 5 5 - ---------------------------------------------------------------------------------------------------------- Derivative financial instruments (B) (49) 29 61 - ---------------------------------------------------------------------------------------------------------- Dividend on preferred securities (C) (5) (6) (6) - ---------------------------------------------------------------------------------------------------------- Revaluation of preferred securities (C) 18 1 (8) - ---------------------------------------------------------------------------------------------------------- Accretion of asset retirement obligation (D) (37) -- -- - ---------------------------------------------------------------------------------------------------------- Cumulative effect of change in accounting policy (D) (4) -- -- - ---------------------------------------------------------------------------------------------------------- Tax effect of flow-through shares (E) -- (1) -- ========================================================================================================== Net earnings - US GAAP $ 1,354 $ 603 $ 708 ========================================================================================================== Net earnings - US GAAP per common share - ---------------------------------------------------------------------------------------------------------- Basic $ 10.09 $ 4.72 $ 5.84 - ---------------------------------------------------------------------------------------------------------- Diluted $ 9.76 $ 4.56 $ 5.70 ==========================================================================================================
78 CANADIAN NATURAL Comprehensive income under US GAAP would be as follows:
(millions of Canadian dollars) Notes 2003 2002 2001 ========================================================================================================== Net earnings - US GAAP $ 1,354 $ 603 $ 708 - ---------------------------------------------------------------------------------------------------------- Adoption of FAS 133 (B) -- -- (124) - ---------------------------------------------------------------------------------------------------------- Amortization of FAS 133 adjustment (B) 20 31 54 - ---------------------------------------------------------------------------------------------------------- Foreign currency translation adjustment (F) (7) (49) 73 ========================================================================================================== Comprehensive income $ 1,367 $ 585 $ 711 ==========================================================================================================
The application of US GAAP would have the following effects on the consolidated balance sheets as reported:
2003 - ---------------------------------------------------------------------------------------------------------- CANADIAN INCREASE US (millions of Canadian dollars) Notes GAAP (DECREASE) GAAP ========================================================================================================== Property, plant and equipment (A,D) $ 13,269 $ 385 $ 13,654 - ---------------------------------------------------------------------------------------------------------- Derivative financial instruments asset (liability) (B) $ -- $ 16 $ 16 - ---------------------------------------------------------------------------------------------------------- Long-term debt (C) $ 2,645 $ 103 $ 2,748 - ---------------------------------------------------------------------------------------------------------- Asset retirement obligation (D) $ 447 $ 450 $ 897 - ---------------------------------------------------------------------------------------------------------- Future income tax (A,B,D) $ 3,588 $ -- $ 3,588 - ---------------------------------------------------------------------------------------------------------- Shareholders' equity $ 6,117 $ (152) $ 5,965 ========================================================================================================== 2002 - ---------------------------------------------------------------------------------------------------------- Canadian Increase US (millions of Canadian dollars) Notes GAAP Decrease) GAAP ========================================================================================================== Property, plant and equipment (A) $ 2,500 $ (68) $ 12,432 - ---------------------------------------------------------------------------------------------------------- Derivative financial instruments asset (liability) (B) $ -- $ 56 $ 56 - ---------------------------------------------------------------------------------------------------------- Long-term debt (C) $ 4,074 $ 126 $ 4,200 - ---------------------------------------------------------------------------------------------------------- Future income tax (A,B) $ 3,188 $ 4 $ 3,192 ========================================================================================================== Shareholders' equity $ 4,868 $ (142) $ 4,726 ==========================================================================================================
NOTES: (A) Using Canadian full cost accounting rules, costs capitalized in each cost centre, net of future income taxes and future site restoration costs, are limited to an amount equal to the undiscounted, unescalated future net revenues from proved reserves plus the lower of cost or estimated fair market value of unproved properties (the "ceiling test"). Under the full cost method of accounting as set forth by the US Securities and Exchange Commission, the ceiling test differs from Canadian GAAP in that future net revenues from proved reserves are discounted at 10% and estimated future financing and administrative expenses are not deducted from net revenues. (B) The Company uses certain derivative financial instruments to manage its commodity prices and foreign currency exposure in relation to future firmly committed and anticipated sales transactions. The Company has also used interest rate swaps to manage its interest rate exposure. Under Canadian GAAP, these derivative financial instruments are accounted for as hedges. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("FAS") 133 "Accounting for Derivative Instruments and Hedging Activities" and FAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities" to account for its commodity prices and interest rate swap derivative financial instruments under US GAAP. Under FAS 133, all derivative financial instruments are recognized in the consolidated balance sheets at their fair value. Changes in the fair value of derivative financial instruments are recognized in consolidated net earnings unless specific criteria for hedging are met. In 2003, 2002 and 2001, no derivative financial instruments were designated as hedges for US GAAP purposes. In 2001, the adoption of FAS 133 resulted in the Company recognizing a derivative financial instruments liability of $183 million and a charge to comprehensive income of $124 million, net of future income tax recoveries of $59 million. Of the initial liability recognized on January 1, 2001, a loss of $54 million, net of future income tax recoveries of $26 million, was reclassified to net earnings during 2001. For 2002, a loss of $31 million, net of future income tax recoveries of $15 million, was amortized to net earnings. For 2003, a loss of $20 million, net of future income tax recoveries of $9 million, was amortized to net earnings. Under US GAAP, foreign currency swap contracts used to hedge foreign currency exposure to anticipated, but not firmly committed, transactions cannot be accounted for as hedges. Accordingly, for US GAAP reporting, gains and losses from changes in the fair market value of foreign currency swap contracts related to these anticipated transactions are recognized in net earnings when those changes in market value occur. 79 ANNUAL REPORT 2003 Notes to the consolidated financial statements (C) Under Canadian GAAP, the preferred securities are considered to be equity because the Company has the unrestricted right to pay dividends, principal and principal prepayments with common shares. Under US GAAP, the Company's preferred securities would be classified as debt rather than as equity. Accordingly, the dividend on the preferred securities would be classified as an expense rather than a dividend and the revaluation of preferred securities would be included in foreign exchange (gain) loss in determining consolidated net earnings. (D) Effective January 1, 2003, the Company adopted FAS 143 "Accounting for Asset Retirement Obligations" for US GAAP reporting purposes. Under FAS 143, all statutory, contractual, and legal obligations relating to asset retirements are recognized in the consolidated balance sheets at their fair value. The liability is adjusted for accretion of discount and any changes in the amount or timing of the underlying cash flows. The standard requires the cumulative effect on prior years to be included in net earnings. Adoption of FAS 143 had the following effects on the Company's consolidated financial statements: (millions of Canadian dollars) DECEMBER 31, 2003 ================================================================================ Consolidated balance sheet - -------------------------------------------------------------------------------- Increase property, plant and equipment $ 445 - -------------------------------------------------------------------------------- Increase asset retirement obligation $ 450 - -------------------------------------------------------------------------------- Increase future income tax liability $ 3 - -------------------------------------------------------------------------------- Consolidated statement of earnings, net of tax - -------------------------------------------------------------------------------- Decrease depletion, depreciation and amortization $ (33) - -------------------------------------------------------------------------------- Increase accretion of asset retirement obligation $ 37 - -------------------------------------------------------------------------------- Increase cumulative effect of change in accounting policy $ 4 ================================================================================ The Company's pipelines and co-generation plant have indeterminant lives and therefore the fair values of the related asset retirement obligations cannot be reasonably determined. The asset retirement obligation for these assets will be recorded in the year in which the lives of the assets are determinable. (E) Under Canadian GAAP, the future income tax effect of flow-through shares is deducted from share capital. However, under US GAAP, the future income tax effect of flow-through shares is expensed immediately. (F) Under US GAAP, exchange gains and losses arising from the translation of self-sustaining foreign operations are included in comprehensive income. (G) Recently Issued Accounting Standards FULL COST ACCOUNTING IN THE OIL AND GAS INDUSTRY In September 2003, the CICA issued Accounting Guideline 16 "Oil and Gas Accounting - Full Cost". The Guideline modifies the ceiling test, which limits the aggregate capitalized costs that may be carried forward to future periods. Specific new guidance was provided on several issues, including the frequency of conducting cost centre impairment tests, the testing for cost centre recoverability and the method of determining fair value. The Guideline recommends that cost centre impairment tests should be conducted at each annual balance sheet date. Recovery of costs is tested by comparing the carrying amount of the oil and natural gas assets to the undiscounted cash flows from those assets using proved reserves and expected future prices and costs. If the carrying amount exceeds the recoverable amount, then impairment should be recognized on the amount by which the carrying amount of the assets exceeds the present value of expected cash flows using proved and probable reserves and expected future prices and costs. The effective date of the Guideline is for fiscal years beginning on or after January 1, 2004, with early adoption recommended. This guideline will apply to the ceiling test relating to the impairment of the Company's property, plant and equipment. Adoption of this standard would not have had an impact on the Company's financial statements for the year ended December 31, 2003. ASSET RETIREMENT OBLIGATIONS In January 2003, the CICA issued Section 3110 "Asset Retirement Obligations". The Section requires the recognition of the fair value of the retirement obligation for related long-term assets as a liability. Retirement costs equal to the retirement obligation are capitalized as part of the cost of the associated capital asset and amortized to expense through depletion over the life of the asset. In subsequent periods, the liability is adjusted for the passage of time and any changes in the amount or timing of the underlying future cash flows. This standard will be adopted retroactively effective January 1, 2004, and prior period comparative balances will be restated. Adoption of the standard will have the following effects on the Company's financial statements: (millions of Canadian dollars) January 1, 2004 ================================================================================ Consolidated balance sheet - -------------------------------------------------------------------------------- Increase property, plant and equipment $ 445 - -------------------------------------------------------------------------------- Increase asset retirement obligation $ 450 - -------------------------------------------------------------------------------- Increase future income tax liability $ 3 - -------------------------------------------------------------------------------- Decrease foreign currency translation adjustment $ (14) - -------------------------------------------------------------------------------- Increase retained earnings $ 6 ================================================================================ 80 CANADIAN NATURAL The Company's pipelines and co-generation plant have indeterminant lives and therefore the fair values of the related asset retirement obligations cannot be reasonably determined. The asset retirement obligation for these assets will be recorded in the year in which the lives of the assets are determinable. LIABILITIES AND EQUITY In January 2004, the CICA issued amendments to Section 3860 "Financial Instruments". The amended Section requires the recognition of certain financial instruments that may be settled in cash or by an issuer's own equity instruments, at the issuer's discretion, as liabilities. This amended Section is effective for periods ending after November 1, 2004, and will require the Company to reclassify its preferred securities from shareholders' equity to long-term debt. Dividends on the preferred securities would be reclassified to interest expense. ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS In January 2003, the CICA issued Section 3063 "Impairment of Long-lived Assets" effective for fiscal years beginning on or after April 1, 2003. The Section indicates that impairment losses occur when the carrying value of the asset exceeds the sum of the undiscounted cash flows expected from its use and is measured as the amount by which the carrying amount exceeds its fair value. This Section will apply to the Company's midstream operating segment only. HEDGING RELATIONSHIPS In December 2001, the CICA issued Accounting Guideline 13, "Hedging Relationships". The effective date of this Guideline was deferred to fiscal years beginning on or after July 1, 2003. The Guideline addresses the types of items that qualify for hedge accounting, the formal documentation required to enable the use of hedge accounting and the requirement to evaluate hedges for effectiveness. The Guideline does not specify how hedge accounting should be applied but does require financial instruments that are not designated as hedges be recorded at fair value on the Company's consolidated balance sheet, with changes in fair value recorded in earnings. This Guideline will be adapted prospectively effective January 1, 2004 and will have the following effects on the Company's financial statements: (millions of Canadian dollars) January 1, 2004 ================================================================================ Consolidated balance sheet - -------------------------------------------------------------------------------- Increase derivative financial instruments asset $ 16 - -------------------------------------------------------------------------------- Increase future income tax liability $ 7 - -------------------------------------------------------------------------------- Increase deferred revenue $ 9 ================================================================================ VARIABLE INTEREST ENTITIES In June 2003, the CICA issued Accounting Guideline 15, "Consolidation of Variable Interest Entities" (VIEs) with the purpose of harmonizing Canadian Standards with FASB Interpretation No. 46 "Consolidation of Variable Interest Entities". The Guideline requires enterprises to identify VIEs in which they have an interest, determine if they are the primary beneficiary of such entities and if so, consolidate them. A transitional provision to disclose VIEs prior to the effective date of the Guideline was to be effective January 1, 2004; however, the CICA has suspended this provision pending review of recent changes to Interpretation No. 46, which are described in Interpretation 46R. The prospective treatment of the consolidation requirement of the Guideline remains effective for all annual and interim periods beginning on or after November 1, 2004. This supplementary oil and natural gas information is provided in accordance with the United States FAS 69, "Disclosures about Oil and Gas Producing Activities", and where applicable is reconciled to the US GAAP financial information. 81 ANNUAL REPORT 2003 EX-99 6 ex4-form40f_2003.txt EXHIBIT 4 EXHIBIT 4 --------- - ------------------------------------ ----------------------------------------- SUPPLEMENTARY OIL & GAS INFORMATION (UNAUDITED) - ------------------------------------ ----------------------------------------- This supplementary oil and natural gas information is provided in accordance with the United States FAS 69, "Disclosures about Oil and Gas Producing Activities", and where applicable is reconciled to the US GAAP financial information. NET PROVED OIL AND NATURAL GAS RESERVES The Company retains independent petroleum engineering consultants to evaluate the majority of the Company's proved oil and natural gas reserves, with the remainder evaluated by the Company's internal petroleum engineers. o For the year ended December 31, 2003, the reports by Sproule Associates Limited ("Sproule") covered 100% of the Company's reserves; o For the year ended December 31, 2002, the reports by Sproule covered 89% of the Company's reserves; and o For the year ended December 31, 2001, the reports by Sproule covered 91% of the Company's reserves. Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Estimates of oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change. The following table summarizes the Company's proved and proved developed oil and natural gas reserves, net of royalties, as at December 31, 2003, 2002 and 2001:
OIL AND NATURAL GAS LIQUIDS (mmbbl) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL ======================================================================================================== Net proved reserves - -------------------------------------------------------------------------------------------------------- RESERVES, DECEMBER 31, 2000 568 93 30 691 - -------------------------------------------------------------------------------------------------------- Extensions and discoveries 13 -- 37 50 - -------------------------------------------------------------------------------------------------------- Purchases of reserves in place 14 -- 8 22 - -------------------------------------------------------------------------------------------------------- Sales of reserves in place (1) -- -- (1) - -------------------------------------------------------------------------------------------------------- Production (54) (13) (1) (68) - -------------------------------------------------------------------------------------------------------- Revisions of previous estimates 43 (2) (14) 27 ======================================================================================================== RESERVES, DECEMBER 31, 2001 583 78 60 721 - -------------------------------------------------------------------------------------------------------- Extensions and discoveries 26 1 14 41 - -------------------------------------------------------------------------------------------------------- Purchases of reserves in place 44 114 -- 158 - -------------------------------------------------------------------------------------------------------- Sales of reserves in place (1) (18) -- (19) - -------------------------------------------------------------------------------------------------------- Production (55) (13) (2) (70) - -------------------------------------------------------------------------------------------------------- Revisions of previous estimates (26) 40 3 17 ======================================================================================================== RESERVES, DECEMBER 31, 2002 571 202 75 848 - -------------------------------------------------------------------------------------------------------- Extensions and discoveries 55 -- 13 68 - -------------------------------------------------------------------------------------------------------- Improved recovery 9 -- -- 9 - -------------------------------------------------------------------------------------------------------- Purchases of reserves in place 7 27 -- 34 - -------------------------------------------------------------------------------------------------------- Sales of reserves in place -- -- -- -- - -------------------------------------------------------------------------------------------------------- Production (56) (21) (4) (81) - -------------------------------------------------------------------------------------------------------- Revisions of previous estimates 2 14 1 17 ======================================================================================================== RESERVES, DECEMBER 31, 2003 588 222 85 895 - -------------------------------------------------------------------------------------------------------- Net proved developed reserves: - -------------------------------------------------------------------------------------------------------- December 31, 2000 328 61 2 391 - -------------------------------------------------------------------------------------------------------- December 31, 2001 344 51 20 415 - -------------------------------------------------------------------------------------------------------- December 31, 2002 340 107 27 474 - -------------------------------------------------------------------------------------------------------- DECEMBER 31, 2003 348 138 23 509 ========================================================================================================
82 ANNUAL REPORT 2003
NATURAL GAS (bcf) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL ======================================================================================================== Net proved reserves - -------------------------------------------------------------------------------------------------------- RESERVES, DECEMBER 31, 2000 1,895 91 53 2,039 - -------------------------------------------------------------------------------------------------------- Extensions and discoveries 379 -- -- 379 - -------------------------------------------------------------------------------------------------------- Purchases of reserves in place 134 -- 23 157 - -------------------------------------------------------------------------------------------------------- Sales of reserves in place (20) -- -- (20) - -------------------------------------------------------------------------------------------------------- Production (255) (4) -- (259) - -------------------------------------------------------------------------------------------------------- Revisions of previous estimates (69) 7 (9) (71) ======================================================================================================== RESERVES, DECEMBER 31, 2001 2,064 94 67 2,225 - -------------------------------------------------------------------------------------------------------- Extensions and discoveries 106 -- 4 110 - -------------------------------------------------------------------------------------------------------- Purchases of reserves in place 699 18 -- 717 - -------------------------------------------------------------------------------------------------------- Sales of reserves in place (3) (56) -- (59) - -------------------------------------------------------------------------------------------------------- Production (346) (10) (1) (357) - -------------------------------------------------------------------------------------------------------- Revision of previous estimates (74) 25 1 (48) ======================================================================================================== RESERVES, DECEMBER 31, 2002 2,446 71 71 2,588 - -------------------------------------------------------------------------------------------------------- Extensions and discoveries 301 -- 6 307 - -------------------------------------------------------------------------------------------------------- Improved recovery 8 -- -- 8 - -------------------------------------------------------------------------------------------------------- Purchases of reserves in place 50 19 -- 69 - -------------------------------------------------------------------------------------------------------- Sales of reserves in place (3) -- -- (3) - -------------------------------------------------------------------------------------------------------- Production (355) (17) (3) (375) - -------------------------------------------------------------------------------------------------------- Revision of previous estimates (21) (11) (10) (42) ======================================================================================================== RESERVES, DECEMBER 31, 2003 2,426 62 64 2,552 - -------------------------------------------------------------------------------------------------------- Net proved developed reserves: - -------------------------------------------------------------------------------------------------------- December 31, 2000 1,569 32 -- 1,601 - -------------------------------------------------------------------------------------------------------- December 31, 2001 1,845 19 16 1,880 - -------------------------------------------------------------------------------------------------------- December 31, 2002 2,185 57 27 2,269 - -------------------------------------------------------------------------------------------------------- DECEMBER 31, 2003 2,140 46 12 2,198 ========================================================================================================
CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS ACTIVITIES
2003 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Proved properties $ 15,125 $ 1,917 $ 568 $ 17,610 - ----------------------------------------------------------------------------------------------------------- Unproved properties 789 56 237 1,082 =========================================================================================================== 15,914 1,973 805 18,692 - ----------------------------------------------------------------------------------------------------------- Less: accumulated depletion and depreciation (4,984) (534) (140) (5,658) =========================================================================================================== Net capitalized costs $ 10,930 $ 1,439 $ 665 $ 13,034 =========================================================================================================== 2002 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Proved properties $ 13,197 $ 1,559 $ 480 $ 15,236 - ----------------------------------------------------------------------------------------------------------- Unproved properties 667 62 132 861 =========================================================================================================== 13,864 1,621 612 16,097 - ----------------------------------------------------------------------------------------------------------- Less: accumulated depletion and depreciation (3,679) (344) (94) (4,117) =========================================================================================================== Net capitalized costs $ 10,185 $ 1,277 $ 518 $ 11,980 =========================================================================================================== 2001 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Proved properties $ 9,001 $ 991 $ 377 $ 10,369 - ----------------------------------------------------------------------------------------------------------- Unproved properties 424 60 48 532 =========================================================================================================== 9,425 1,051 425 10,901 - ----------------------------------------------------------------------------------------------------------- Less: accumulated depletion and depreciation (2,694) (185) (15) (2,894) Net capitalized costs $ 6,731 $ 866 $ 410 $ 8,007 ===========================================================================================================
83 ANNUAL REPORT 2003 Supplementary oil & gas information (unaudtied) COSTS INCURRED IN OIL AND NATURAL GAS ACTIVITIES
2003 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Property acquisitions - ----------------------------------------------------------------------------------------------------------- Proved $ 236 $ 100 $ -- $ 336 - ----------------------------------------------------------------------------------------------------------- Unproved 116 23 -- 139 - ----------------------------------------------------------------------------------------------------------- Exploration 190 47 28 265 - ----------------------------------------------------------------------------------------------------------- Development 1,227 193 148 1,568 =========================================================================================================== Finding and development costs 1,769 363 176 2,308 - ----------------------------------------------------------------------------------------------------------- Asset retirement costs 80 59 9 148 - ----------------------------------------------------------------------------------------------------------- Actual retirement expenditures (30) (1) (9) (40) =========================================================================================================== Costs incurred $ 1,819 $ 421 $ 176 $ 2,416 =========================================================================================================== 2002 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Property acquisitions - ----------------------------------------------------------------------------------------------------------- Proved $ 3,367 $ 373 $ -- $ 3,740 - ----------------------------------------------------------------------------------------------------------- Unproved 369 28 30 427 - ----------------------------------------------------------------------------------------------------------- Exploration 96 10 81 187 - ----------------------------------------------------------------------------------------------------------- Development 607 145 74 826 =========================================================================================================== Costs incurred $ 4,439 $ 556 $ 185 $ 5,180 =========================================================================================================== 2001 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Property acquisitions - ----------------------------------------------------------------------------------------------------------- Proved $ 647 $ -- $ 62 $ 709 - ----------------------------------------------------------------------------------------------------------- Unproved 73 4 -- 77 - ----------------------------------------------------------------------------------------------------------- Exploration 61 25 64 150 - ----------------------------------------------------------------------------------------------------------- Development 848 68 78 994 =========================================================================================================== Costs incurred $ 1,629 $ 97 $ 204 $ 1,930 =========================================================================================================== RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES The Company's results of operations from oil and natural gas producing activities for the years ended December 31, 2003, 2002 and 2001 are summarized in the following tables: 2003 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Oil and natural gas revenue, net of royalties $ 3,961 $ 962 $ 150 $ 5,073 - ----------------------------------------------------------------------------------------------------------- Production (845) (314) (38) (1,197) - ----------------------------------------------------------------------------------------------------------- Transportation (263) (30) (1) (294) - ----------------------------------------------------------------------------------------------------------- Depletion, depreciation and amortization (1,203) (250) (42) (1,495) - ----------------------------------------------------------------------------------------------------------- Accretion of asset retirement obligation (23) (39) (1) (63) - ----------------------------------------------------------------------------------------------------------- Petroleum revenue tax -- (97) -- (97) - ----------------------------------------------------------------------------------------------------------- Income tax (673) (93) (24) (790) =========================================================================================================== Results of operations $ 954 $ 139 $ 44 $ 1,137 =========================================================================================================== 2002 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Oil and natural gas revenue, net of royalties $ 3,045 $ 579 $ 99 $ 3,723 - ----------------------------------------------------------------------------------------------------------- Production (656) (229) (35) (920) - ----------------------------------------------------------------------------------------------------------- Transportation (273) (20) -- (293) - ----------------------------------------------------------------------------------------------------------- Depletion, depreciation and amortization (1,024) (193) (80) (1,297) - ----------------------------------------------------------------------------------------------------------- Petroleum revenue tax -- (51) -- (51) - ----------------------------------------------------------------------------------------------------------- Income tax (431) (34) 11 (454) =========================================================================================================== Results of operations $ 661 $ 52 $ (5) $ 708 =========================================================================================================== 2001 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Oil and natural gas revenue, net of royalties $ 2,610 $ 506 $ 41 $ 3,157 - ----------------------------------------------------------------------------------------------------------- Production (597) (123) (27) (747) - ----------------------------------------------------------------------------------------------------------- Transportation (166) (11) -- (177) - ----------------------------------------------------------------------------------------------------------- Depletion, depreciation and amortization (737) (129) (24) (890) - ----------------------------------------------------------------------------------------------------------- Loss on sale of US assets (24) -- -- (24) - ----------------------------------------------------------------------------------------------------------- Petroleum revenue tax -- (59) -- (59) - ----------------------------------------------------------------------------------------------------------- Income tax (447) (55) 3 (499) =========================================================================================================== Results of operations $ 639 $ 129 $ (7) $ 761 ===========================================================================================================
84 CANADIAN NATURAL STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND NATURAL GAS RESERVES AND CHANGES THEREIN The following standardized measure of discounted future net cash flows from proved oil and natural gas reserves has been computed using year-end sales prices and costs and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including: o Future production will include production not only from proved properties, but may also include production from probable and potential reserves; o Future production of oil and natural gas from proved properties will differ from reserves estimated; o Future production rates will vary from those estimated; o Future rather than year-end sales prices and costs will apply; o Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change; o Future estimated income taxes do not take into account the effects of future exploration expenditures; and o Future development and site restoration costs will differ from those estimated. Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company's future net cash flows relating to proved oil and natural gas reserves based on the standardized measure as prescribed in FAS 69:
2003 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Future cash inflows $ 32,720 $ 9,099 $ 3,192 $ 45,011 - ----------------------------------------------------------------------------------------------------------- Future production costs (9,480) (3,015) (1,179) (13,674) - ----------------------------------------------------------------------------------------------------------- Future development and site restoration costs (2,393) (1,749) (697) (4,839) - ----------------------------------------------------------------------------------------------------------- Future income taxes (7,295) (2,801) -- (10,096) =========================================================================================================== Future net cash flows 13,552 1,534 1,316 16,402 - ----------------------------------------------------------------------------------------------------------- 10% annual discount for timing of future cash flows (6,203) (336) (432) (6,971) =========================================================================================================== Standardized measure of future net cash flows $ 7,349 $ 1,198 $ 884 $ 9,431 =========================================================================================================== 2002 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Future cash inflows $ 34,980 $ 9,682 $ 3,206 $ 47,868 - ----------------------------------------------------------------------------------------------------------- Future production costs (7,238) (3,250) (911) (11,399) - ----------------------------------------------------------------------------------------------------------- Future development and site restoration costs (1,770) (1,691) (616) (4,077) - ----------------------------------------------------------------------------------------------------------- Future income taxes (8,046) (2,991) -- (11,037) =========================================================================================================== Future net cash flows 17,926 1,750 1,679 21,355 - ----------------------------------------------------------------------------------------------------------- 10% annual discount for timing of future cash flows (7,361) (434) (556) (8,351) =========================================================================================================== Standardized measure of future net cash flows $ 10,565 $ 1,316 $ 1,123 $ 13,004 =========================================================================================================== 2001 - ----------------------------------------------------------------------------------------------------------- (millions of Canadian dollars) NORTH AMERICA NORTH SEA OFFSHORE WEST AFRICA TOTAL =========================================================================================================== Future cash inflows $ 18,565 $ 3,089 $ 1,587 $ 23,241 - ----------------------------------------------------------------------------------------------------------- Future production costs (6,587) (1,368) (576) (8,531) - ----------------------------------------------------------------------------------------------------------- Future development and site restoration costs (1,204) (354) (556) (2,114) - ----------------------------------------------------------------------------------------------------------- Future income taxes (2,576) (549) -- (3,125) =========================================================================================================== Future net cash flows 8,198 818 455 9,471 10% annual discount for timing of future cash flows (3,136) (241) (133) (3,510) =========================================================================================================== Standardized measure of future net cash flows $ 5,062 $ 577 $ 322 $ 5,961 ===========================================================================================================
The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table:
(millions of Canadian dollars) 2003 2002 2001 =========================================================================================================== Sales of oil and natural gas produced, net of production costs $ (3,582) $ (2,510) $ (2,232) - ----------------------------------------------------------------------------------------------------------- Net changes in sales prices and production costs (2,750) 8,453 (9,685) - ----------------------------------------------------------------------------------------------------------- Extensions, discoveries and improved recovery 1,360 972 1,027 - ----------------------------------------------------------------------------------------------------------- Changes in estimated future development costs (346) (1,284) (174) - ----------------------------------------------------------------------------------------------------------- Purchases of proved reserves in place 594 4,973 413 - ----------------------------------------------------------------------------------------------------------- Sales of proved reserves in place (8) (494) (34) - ----------------------------------------------------------------------------------------------------------- Revisions of previous reserve estimates 144 360 56 - ----------------------------------------------------------------------------------------------------------- Accretion of discount 2,000 794 1,745 - ----------------------------------------------------------------------------------------------------------- Changes in production timing and other (1,411) 502 (726) - ----------------------------------------------------------------------------------------------------------- Net change in income taxes 426 (4,723) 3,692 =========================================================================================================== Net change (3,573) 7,043 (5,918) - ----------------------------------------------------------------------------------------------------------- Balance - beginning of year 13,004 5,961 11,879 =========================================================================================================== Balance - end of year $ 9,431 $ 13,004 $ 5,961 ===========================================================================================================
85 ANNUAL REPORT 2003 EX-31 7 ex5-form40f_2003.txt EXHIBIT 5 EXHIBIT 5 --------- CERTIFICATION REQUIRED BY RULE 13a-14(a) OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF 1934 CERTIFICATION I, John G. Langille, President of Canadian Natural Resources Limited, certify that: 1. I have reviewed this annual report on Form 40-F of Canadian Natural Resources Limited; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; 4. The issuer's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the issuer and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and 5. The issuer's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of issuer's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. Dated this 23rd day of April, 2004. /s/ John G. Langille - ----------------------------- John G. Langille President (Principal Executive Officer), Canadian Natural Resources Limited EX-31 8 ex6-form40f_2003.txt EXHIBIT 6 EXHIBIT 6 --------- CERTIFICATION REQUIRED BY RULE 13a-14(a) OR 15d-14 OF THE SECURITIES EXCHANGE ACT OF 1934 CERTIFICATION I, Douglas A. Proll, Senior Vice President, Finance of Canadian Natural Resources Limited, certify that: 1. I have reviewed this annual report on Form 40-F of Canadian Natural Resources Limited; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report; 4. The issuer's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the issuer and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusion about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and 5. The issuer's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of issuer's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting. Dated this 23rd day of April, 2004. /s/ Douglas A. Proll - ----------------------------- Douglas A. Proll Senior Vice President, Finance (Principal Financial Officer), Canadian Natural Resources Limited EX-32 9 ex7-form40f_2003.txt EXHIBIT 7 EXHIBIT 7 --------- CERTIFICATION CERTIFICATION REQUIRED BY RULE 13A-14(b) AND SECTION 1350 OF CHAPTER 63 OF TITLE 18 OF THE UNITED STATES CODE In connection with the report of Canadian Natural Resources Limited. (the "Company") on the Form 40-F for the fiscal year ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. DATED this 23rd day of April, 2004. /s/ John G. Langille - ------------------------------ John G. Langille President (Principal Executive Officer), Canadian Natural Resources Limited EX-32 10 ex8-form40f_2003.txt EXHIBIT 8 EXHIBIT 8 --------- CERTIFICATION CERTIFICATION REQUIRED BY RULE 13A-14(b) AND SECTION 1350 OF CHAPTER 63 OF TITLE 18 OF THE UNITED STATES CODE In connection with the report of Canadian Natural Resources Limited. (the "Company") on the Form 40-F for the fiscal year ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. DATED this 23rd day of April, 2004. /s/ Douglas A. Proll - ----------------------------- Douglas A. Proll Senior Vice President, Finance (Principal Financial Officer), Canadian Natural Resources Limited EX-23 11 ex9-form40f_2003.txt EXHIBIT 9 EXHIBIT 9 --------- [LETTERHEAD OF PRICEWATERHOUSECOOPERS LLP] PRICEWATERHOUSECOOPERS LLP CHARTERED ACCOUNTANTS 111 5th Avenue SW, Suite 3100 Calgary, Alberta Canada T2P 5L3 Telephone +1 (403) 509 7500 Facsimile +1 (403) 781 1825 CONSENT OF INDEPENDENT AUDITORS - ------------------------------- We consent to the use of our report dated February 19, 2004, with respect to the consolidated financial statements of Canadian Natural Resources Limited included in its Annual Report (Form 40-F) for the year ended December 31, 2003 and incorporated by reference in its Registration Statement on Form F-9 (Registration No. 333-104919), filed with the Securities and Exchange Commission. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Calgary, Alberta April 9, 2004 EX-23 12 ex10-form40f_2003.txt EXHIBIT 10 EXHIBIT 10 ---------- [LETTERHEAD OF SPROULE ASSOCIATES LIMITED] SPROULE ASSOCIATES LIMITED Ref.: 1808.14933 March 29, 2004 Mr. Larry Galea, Manager, Operations Planning Canadian Natural Resources Limited 2500, 855 Second Street SW Calgary AB T2P 4J8 RE: CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS Dear Mr. Galea: We consent to the use of our report with respect to the reserves data of Canadian Natural Resources Limited incorporated by reference in its (i) Annual Report (Form 40-F) for the year ended December 31, 2003 and (ii) Registration Statement on Form F-9 (Registration No. 333-104919), filed with the Securities and Exchange Commission. Sincerely, /s/ Harry J. Helwerda ------------------------------ Harry J. Helwerda, P.Eng. Vice-President, Engineering, Canada and U.S. HJH:db 900, 140 Fourth Ave SW; Calgary AB T2P 3N3 Canada; Tel: (403) 294-5500, Fax: (403) 294-5590 1675 Broadway, Suite 1130, Denver CO 80202 U.S.A.; Tel: (303) 592-8770, Fax: (303) 592-8771 1001 Fannin, Suite 550, Houston TX 77002 U.S.A.; Tel: (713) 652-5140, Fax: (713) 652-5143 Toll Free: 1-877-777-6135 info@sproule.com, www.sproule.com -----END PRIVACY-ENHANCED MESSAGE-----