-----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, GiTN8feaadram19WIfbXwgPFQp58HpYal/DZiab1iitIyKEf9TDEURx41A9gxS6b 07u0JlyESFvlsZ0VPuPRqQ== 0000950142-05-001088.txt : 20050401 0000950142-05-001088.hdr.sgml : 20050401 20050331173237 ACCESSION NUMBER: 0000950142-05-001088 CONFORMED SUBMISSION TYPE: 40-F PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050401 DATE AS OF CHANGE: 20050331 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: 05722146 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_2004.txt ANNUAL REPORT - 2004 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, 2004 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. 268,180,123 Common Shares outstanding as of December 31, 2004 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, 2004, 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, 2004 and 2003, 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 17 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, 2004, 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, 2004, see Exhibit 4 of this Annual Report on Form 40-F. Controls and Procedures As of the end of the registrant's fiscal year ended December 31, 2004, an evaluation of the effectiveness of CNRL's "disclosure controls and procedures" (as such term is defined in Rules 13a-15(c) and 15(d)-15(e) of the Securities Exchange Act of 1934, as amended (the "Exchange Act") was carried out by CNRL's principal executive officer and principal financial officer. Based upon the evaluation, CNRL's principle executive officer and principal financial officer have concluded that as of the end of the fiscal year, CNRL's disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in applicable Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the registrant's management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. It should be noted that while CNRL's principal executive officer and principal financial officer believe that CNRL's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the CNRL's disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. 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, D. A. Tuer and Ms. C.M. Best who chairs the Audit Committee. Audit Committee Financial Expert The Board of Directors of CNRL has determined that Ms. C.M. Best qualifies 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. 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, 2004 and December 31, 2003, for professional services rendered by PWC for the audit of its annual financial statements in connection with statutory and regulatory filings or engagements for those fiscal years, reviews of the first, second and third quarter Consolidated Financial Statements and annual audits of CNRL's subsidiary financial statements are $1,100,548 and $886,000, respectively. Audit-Related Fees: The aggregate fees billed for each of the last two fiscal years of CNRL, ending December 31, 2004 and December 31, 2003, for audit-related services by PWC consisting of regulatory changes consultation provided in 2004 including Sarbanes-Oxley Section 404 consultation, debt covenant compliance and Crown Royalty Statement audit were $183,663 and $12,500 respectively. CNRL's Audit Committee approved all of these audit-related services. Tax Fees: The aggregate fees billed for each of the last two fiscal years of CNRL, ending December 31, 2004 and December 31, 2003, for professional services rendered by PWC for tax-related services consisting of payroll tax filing consultation provided in 2004 and consultation on tax matters for foreign subsidiaries, transfer pricing study and other professional services related to tax matters provided in 2003 were $39,330 and $11,000, respectively. CNRL's Audit Committee approved all of these tax-related services. All Other Fees: No other services were provided in the last fiscal year ending December 31, 2004. Fees for other services, payroll consultation and training provided in 2003 were $10,000. CNRL's Audit Committee approved all of the noted services. Audit Committee Pre-Approval Policies and Procedures: The Audit Committee's duties and responsibilities include the review and approval of fees to be paid to the independent auditors, scope and timing of the audit and other related services rendered by the independent auditors. The Audit Committee also reviews and approves the independent auditor's annual audit plan, including scope, staffing, locations and reliance upon management and internal audit department prior to the commencement of the audit and reviews and approves proposed non-audit services to be provided by the independent auditors except those non-audit services prohibited by legislation. Off-balance Sheet Arrangements CNRL does not have any off-balance sheet arrangements that have or are reasonably likely to have an effect on its results of operations or financial condition. See page 57 of CNRL's Management's Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2004, filed herewith, under the caption "Committments and off balance sheet arrangements". Contractual Obligations CNRL has various commitments primarily related to debt, operating leases and demand charges on firm transportation agreements. The following table summarizes CNRL's commitments as at December 31, 2004.
- --------------------------------------------------------------------------------------------- ($ millions) Total 2005 2006 2007 2008 2009 Thereafter - --------------------------------------------------------------------------------------------- Natural gas transportation 724 194 147 100 78 37 168 - --------------------------------------------------------------------------------------------- Crude oil transportation and pipeline 210 11 9 11 12 13 154 - --------------------------------------------------------------------------------------------- Offshore equipment operating lease 486 110 48 48 48 48 184 - --------------------------------------------------------------------------------------------- Baobab Project 99 99 -- -- -- -- -- - --------------------------------------------------------------------------------------------- Offshore drilling and other 133 125 8 -- -- -- -- - --------------------------------------------------------------------------------------------- Electricity 129 26 28 20 13 8 34 - --------------------------------------------------------------------------------------------- Office lease 141 21 21 22 23 24 30 - --------------------------------------------------------------------------------------------- Processing 7 5 2 -- -- -- -- - --------------------------------------------------------------------------------------------- Horizon Project 99 99 -- -- -- -- -- - --------------------------------------------------------------------------------------------- Long-term debt 3,175 194 -- 162 37 69 2,713 - --------------------------------------------------------------------------------------------- Total 5,203 884 263 363 211 199 3,283 =============================================================================================
Code of Ethics CNRL has had a long-standing Code of Integrity, Business Ethics and Conduct, which covers 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 executive sessions at each regularly scheduled Board of Directors meeting 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 30th day of March, 2005. 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, 2004. 2. Consolidated Financial Statements for the fiscal years ended December 31, 2004 and 2003 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, 2004. 4. Supplementary Oil & Gas Information for the fiscal year ended December 31, 2004. 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. 11. Consent of Ryder Scott Company, independent petroleum engineering consultants. 12. Consent of Gilbert Laustsen Jung Associates Ltd., independent petroleum engineering consultants. EX-99 2 ex-1form40f_2004.txt EXHIBIT 1 EXHIBIT 1 --------- CANADIAN NATURAL RESOURCES LIMITED ANNUAL INFORMATION FORM March 30, 2005 1 TABLE OF CONTENTS DEFINITIONS....................................................................3 SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................4 THE COMPANY....................................................................6 GENERAL DEVELOPMENT OF THE BUSINESS............................................7 REGULATORY MATTERS.............................................................9 RISK FACTORS..................................................................10 ENVIRONMENTAL MATTERS.........................................................14 DESCRIPTION OF THE BUSINESS...................................................14 A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES.............................16 Drilling Activity..........................................................17 Producing Oil and Natural Gas Wells........................................18 Northeast British Columbia.................................................18 Northwest Alberta..........................................................20 Northern Plains............................................................21 Southern Plains and Southeast Saskatchewan.................................23 United Kingdom North Sea...................................................24 Offshore West Africa.......................................................25 Cote d'Ivoire..............................................................26 Angola.....................................................................26 Horizon Oil Sands Project..................................................27 B. CRUDE OIL AND NATURAL GAS RESERVES.........................................28 C. RECONCILIATION OF CHANGES IN NET RESERVES..................................33 D. OIL SANDS MINING RESERVES..................................................34 E. CRUDE OIL AND NATURAL GAS PRODUCTION.......................................34 F. HISTORICAL DRILLING ACTIVITY BY PRODUCT....................................38 G. CAPITAL EXPENDITURES.......................................................39 H. NON-RESERVE ACREAGE........................................................41 I. DEVELOPED ACREAGE..........................................................41 SELECTED FINANCIAL INFORMATION................................................42 CAPITAL STRUCTURE.............................................................43 2 MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................45 DIVIDEND HISTORY..............................................................46 TRANSFER AGENTS and REGISTRAR.................................................46 DIRECTORS AND EXECUTIVE OFFICERS..............................................47 AUDIT COMMITTEE INFORMATION...................................................51 LEGAL PROCEEDINGS.............................................................52 INTERESTS OF EXPERTS..........................................................52 ADDITIONAL INFORMATION........................................................52 SCHEDULE "A"..................................................................53 SCHEDULE "B"..................................................................56 CURRENCY Unless otherwise indicated, all dollar figures stated in this Annual Information Form represent Canadian dollars. 3 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. "BOE" or "boe" means natural gas is converted to oil equivalent at the rate of six thousand cubic feet equals one barrel of oil equivalent. "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. "mbbl" means one thousand barrels. "mcf" means one thousand cubic feet. "mcf/d" means one thousand cubic feet per day. "mmbbl" 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. 4 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. Special Note Regarding Currency, Production and Reserves In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves and production data is presented on a before royalties basis unless otherwise stated. In addition, reference is made to oil and natural gas in common units called barrel of oil equivalent ("boe"). A boe is derived by converting six thousand cubic feet of natural gas to one barrel of 5 crude oil (6mcf:1bbl). This conversion may be misleading, particularly if used in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. Canadian Natural retains qualified independent reserves evaluators to evaluate the Company's proved and probable oil and natural gas reserves and prepare Evaluation Reports on the Company's total reserves. Canadian Natural has been granted an exemption from 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 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 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 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 two standards is not material. The Board of Directors of the Company has a Reserves Committee, which has met with each of the Company's third party reserve evaluators and carried out independent due diligence procedures with them as to the Company's reserves. Reserves and net asset values presented for years prior to 2003 were evaluated in accordance with the standards of National Policy 2-B which has now been replaced by NI 51-101. The stated reserves were reasonably evaluated as economically productive using year-end costs and prices escalated at appropriate rates throughout the productive life of the properties. Horizon oil sands mining reserves have been evaluated under SEC Industry Guide 7. Resource potential as determined for thermal oil assets and other potential mining leases are determined using generally accepted industry methodologies for resource delineation based upon stratigraphic well drilling completed on the properties. 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 (net earnings before interest, taxes, depreciation depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, stock-based compensation expense and unrealized risk management activity). 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 of 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. 6 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.) Investments 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. CNRL as the managing partner and Renata Resources Inc. are the partners of Canadian Natural Resources 2005 Partnership, a general partnership which holds certain natural gas facilities situated in Alberta. The consolidated financial statements of CNRL include the accounts of the Company and all of its subsidiaries and partnerships. 7 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, 2004 the Company had 2,137 full time employees in North America and 273 full time employees in its international operations. 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 included approximately 2.9 million net acres of undeveloped lands and provided 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. 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. 8 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. In February 2004, the Company completed the acquisition of 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 at the time of the acquisition 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 Northern Plains. In April 2004, the Company completed an acquisition of certain oil and natural gas properties located in Northeast British Columbia and Northwest Alberta for consideration of $280 million. The properties at the time of acquisition were producing approximately 68 million cubic feet per day of natural gas and 200 barrels per day of light crude oil and natural gas liquids and contain over 415 thousand acres of developed and undeveloped land. The properties included a further interest in the Ladyfern natural gas field. The portion of the Ladyfern field included in the acquisition included production of approximately 50 million cubic feet per day of natural gas. As part of this acquisition, the Company also acquired undeveloped acreage in the Foothills area of Alberta and British Columbia. This area is characterized by large, undeveloped pools with significant natural gas potential in deeper zones and will add a new exploration base in the Alberta Foothills, complementing the Company's existing holdings and production base in the British Columbia Foothills. In the third quarter of 2004 the Company's wholly owned subsidiary, CNR International (U.K.) Limited acquired certain oil and natural gas properties in the central North Sea. The acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma fields) and B-Block (Balmoral, Stirling and Glamis fields) together with associated production facilities and adjacent exploration acreage. On December 1, 2004 the Company issued US $350.0 million of 10 year 4.90 per cent unsecured notes maturing December 1, 2014 and US $350.0 million of 30 year 5.85 per cent unsecured notes maturing February 1, 2035 pursuant to a short form shelf prospectus dated May 8, 2003. In December 2004, the Company acquired certain oil and natural gas properties located in Alberta and British Columbia, for an aggregate cash consideration of approximately $703 million, net of proceeds received from an agreement to concurrently dispose of a portion of such properties for approximately $50 million and cash flows realized from the effective date of September 1, 2004. At the time of the acquisition production from the properties acquired by Canadian Natural, after the above noted disposition, was estimated at 105 million cubic feet per day of natural gas and 7,500 barrels per day of light crude oil and NGLs being approximately 25,000 barrels of oil equivalent of daily production on a six to one basis. The acquisition included over 510,000 net acres of undeveloped land. The vast majority of the acquired 9 properties is located in the Company's core areas and extends its Northern Plains core region into the light oil operating area of Dawson. During 2004, the Company completed 109 transactions (including the four acquisitions mentioned above) in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate net expenditure of $1.371 billion (excluding the Petrovera Partnership acquisition described above). 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 $7 million. In February 2005 the Board of Directors of the Company approved Phase 1 of the Horizon Oil Sands Project. See below "Horizon Oil Sands Project". 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 is 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. 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 10 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 39.3 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. 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. Development of the Espoir field on CI-26, and the Baobab Field on CI-40, 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"). RISK FACTORS Volatility of Oil and Natural Gas Prices The Company's financial condition will be substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. Fluctuations in crude oil or natural gas prices could have a material adverse effect on its operations and financial condition and the value and amount of its reserves. Prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond the Company's control. Oil prices are determined by international supply and demand. Factors which affect crude oil prices include the actions of the Organization of Petroleum Exporting Countries, the condition of the Canadian, United States and Asian economies, government regulation, political stability in the Middle East and elsewhere, the foreign supply of oil, the price of foreign imports, the availability of alternate fuel sources and 11 weather conditions. Natural gas prices realized by the Company will be affected primarily in North America by supply and demand, weather conditions and prices of alternate sources of energy. Any substantial or extended decline in the prices of crude oil or natural gas could result in a delay or cancellation of existing or future drilling, development or construction programs or curtailment in production at some properties or resulting unutilized long-term transportation commitments, all of which could have a material adverse effect on Canadian Natural's revenues, profitability and cash flows. Canadian Natural conducts an annual assessment of the carrying value of its assets in accordance with Canadian generally accepted accounting principles. If oil and natural gas prices decline, the carrying value of the assets could be subject to downward revisions, and earnings could be adversely affected. Approximately 27 percent of the Company's 2004 production on a boe basis was primary and thermal heavy oil. The market prices for this heavy oil differ from the established market indices for light and medium grades of oil, due principally to the higher transportation and refining costs associated with heavy oil. As a result, the price received for heavy oil is generally lower than the price for medium and light oil, and the production costs associated with heavy oil are relatively higher than for lighter grades. Future differentials are uncertain and any increase in the heavy oil differentials could have a material adverse effect on the Company's business. Environmental Risks All phases of the oil and natural gas business are subject to environmental regulation pursuant to a variety of Canadian, United States, United Kingdom, European Union and other federal, provincial, state and municipal laws and regulations, as well as international conventions (collectively, "environmental legislation"). Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. Environmental legislation also requires that wells, facility sites and other properties associated with the Company's operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties. The costs of complying with environmental legislation in the future may have a material adverse effect on Canadian Natural's financial condition or results of operations. Canadian Natural anticipates that changes in environmental legislation may require, among other things, reductions in emissions to the air from its operations which may result in increased capital expenditures. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the Company's financial condition or results of operations. 12 Need to Replace Reserves Canadian Natural's future oil and natural gas reserves and production, and therefore its cash flows and results of operations, are highly dependent upon success in exploiting its current reserve base and acquiring or discovering additional reserves. Without additions to reserves through exploration, acquisition or development activities, the Company's reserves and production will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent the Company's cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital investments to maintain and expand its oil and natural gas reserves will be impaired. In addition, Canadian Natural may be unable to find and develop or acquire additional reserves to replace its oil and natural gas production at acceptable costs. Competition in Energy Industry The energy industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the construction and operation of crude oil and natural gas pipelines and facilities, the acquisition of oil and natural gas interests and the transportation and marketing of crude oil, natural gas, natural gas liquids and electricity. Canadian Natural will compete not only among participants in the energy industry, but also between petroleum products and other energy sources. The Company's competitors will include integrated oil and natural gas companies and numerous other senior oil and natural gas companies, some of which may have greater financial and other resources than the Company. Other Business Risks Other business risks include operational risks, the cost of capital available to fund exploration and development programs, regulatory issues and taxation and the requirements of new environmental laws and regulations. Exploring for, producing and transporting petroleum substances involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. These activities are subject to a number of hazards which may result in fires, explosions, spills, blow-outs or other unexpected or dangerous conditions causing personal injury, property damage, environmental damage and interruption of operations. Canadian Natural's liability, property and business interruption insurance may not provide adequate coverage in certain unforeseen circumstances. Foreign Investments The Company's foreign investments involve risks typically associated with investments in developing countries such as uncertain political, economic, legal and tax environments. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risks of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities and quasi-governmental agencies, changes in laws and policies governing operations of foreign-based companies and other uncertainties arising out of foreign government sovereignty over the Company's international operations. In addition, if a dispute arises in its foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of a court in the United States or Canada. 13 Canadian Natural's private ownership of oil and natural gas properties in Canada differs distinctly from its ownership interests in foreign oil and natural gas properties. In some foreign countries in which the Company does and may do business in the future, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of reserves. Accordingly, operations outside of Canada may be materially affected by host governments through royalty payments, export taxes and regulations, surcharges, value added taxes, production bonuses and other charges. In addition, changes in prices and costs of operations, timing of production and other factors may affect estimates of oil and natural gas reserve quantities and future net cash flows attributable to foreign properties in a manner materially different than such changes would affect estimates for Canadian properties. Agreements covering foreign oil and natural gas operations also frequently contain provisions obligating the Company to spend specified amounts on exploration and development or to perform certain operations, or forfeit all or a portion of the acreage subject to the contract. Uncertainty of Reserve Estimates There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Company's control. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flow therefrom are based upon a number of factors and assumptions made as of the date on which the reserve estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Canadian Natural's actual production, revenues, taxes and development, abandonment and operating expenditures with respect to its reserves will likely vary from such estimates, and such variances could be material. Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves. Priority of Subsidiary Indebtedness; Consequences of Holding Corporation Structure The Company carries on business through corporate and partnership subsidiaries. The majority of the Company's assets are held in one or more corporate or partnership subsidiaries. The results of operations and ability to service indebtedness, including debt securities, are dependent upon the results of operations of these subsidiaries and the payment of funds by these subsidiaries to the Company in the form of loans, dividends or otherwise. In the event of the liquidation of any corporate or partnership subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, prior to being used by the Company to pay its indebtedness. 14 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 management 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 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 has participated in Canada's Climate Change Voluntary Challenge & Registry Inc (VCR) and plans to participate in a new Canadian Standards Association (CSA) program when the transition from VCR to CSA is complete. 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 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, 2004, 2003, and 2002. 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. 15 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 crude oil, Pelican Lake crude oil, primary heavy crude oil and thermal heavy crude 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 45 per cent of 2004 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 24 per cent of 2004 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 27 per cent of 2004 production. Other heavy oil, which accounts for 4 per cent of 2004 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 Pelican Lake crude 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 11.5 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. 16 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, 2004. The information is proportionate to the working interests owned by the Company.
2004 AVERAGE DAILY YEAR ENDED PRODUCTION DECEMBER 31, MAJOR INFRASTRUCTURE RATES 2004 AS AT DECEMBER 31, 2004 --------------- ------------ ----------------------- BATTERIES/ OIL & NATURAL UNDEVELOPED COMPRESSORS & PLANTS/ NGLs GAS ACREAGE PLATFORMS REGION Mbbls MMcf (thousands) /FPSO - ------ ----- ------- ----------- --------------------- North America Northeast B. C. 6.8 437.3 2,040 1/8/-/- Northwest Alberta 10.9 303.2 1,660 -/7/-/- Northern Plains 166.3 429.9 6,922 9/5/-/- Southern Plains 12.7 155.5 661 -/-/-/- Southeast Saskatchewan 9.3 3.1 123 -/-/-/- Non - core regions 0.2 1.1 1,822 -/-/-/- Horizon Oil Sands -- -- 117 -/-/-/- International North Sea 64.7 50.4 565 -/-/5/3 Offshore West Africa Cote d'Ivoire 11.6 7.5 276 -/-/1/1 Angola -- -- 610 -/-/-/- South Africa -- 5,550 -/-/-/- ----- ------- ------ --------- Total 282.5 1,388.0 20,346 10/20/6/4 ----- ------- ------ ---------
17 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 three fiscal years up to December 31, 2004 by geographic region:
2004 --------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT ------------------------------ ------------------------------ PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL ---------- --------- ----- ---------- --------- ----- Canada Northeast B. C 23.8 6.2 30 146.8 14.4 161.2 Northwest Alberta 42.8 7.6 50.4 100.4 3.9 104.3 Northern Plains 116.6 26.6 143.2 333.8 23.2 357 Southern Plains 18.5 7.0 25.5 209.9 4.0 213.9 Southeast Saskatchewan -- -- -- 12.5 0 12.5 Non - core regions -- -- -- 0.5 0.3 0.8 North Sea -- 2.0 2.0 9.2 0.0 9.2 Offshore West Africa Cote d'Ivoire -- 0.7 0.7 2.3 0.0 2.3 Angola -- -- -- -- -- -- ----- ---- ----- ----- ---- ----- Total 201.7 50.1 251.8 815.4 45.8 861.2 ----- ---- ----- ----- ---- -----
2003 ----------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT ------------------------------ -------------------------------- PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL ---------- --------- ----- ---------- --------- ------- Canada Northeast B. C 15.5 13.3 28.8 67.8 9.1 76.9 Northwest Alberta 31.7 11.8 43.5 69.9 7.9 77.8 Northern Plains 57.5 26.6 84.1 531.6 37.9 569.5 Southern Plains 33.0 4.0 37.0 387.9 5.0 392.9 Southeast Saskatchewan -- -- -- 26.9 -- 26.9 Non - core regions -- -- -- 0.4 -- 0.4 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 Northeast B. C 16.8 4.4 21.2 25.4 -- 25.4 Northwest Alberta 3.9 3.0 6.9 6.1 -- 6.1 Northern Plains 31.5 6.0 37.5 278.1 8.6 286.7 Southern Plains 12.0 -- 12.0 40.6 2.5 43.1 Southeast Saskatchewan -- -- -- 4.3 1.0 5.3 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 ----- ---- ----- ----- ---- -----
18 Producing Oil & Natural Gas Wells Set forth below is a summary of the number of gross and net wells within the Company that were producing or capable of producing as of December 31, 2004:
NATURAL GAS WELLS OIL WELLS TOTAL WELLS ----------------- --------------- ----------------- GROSS NET GROSS NET GROSS NET ----- ------- ----- ------- ------ -------- Canada Northeast B. C. 937 816.0 173 135.6 1,110 951.7 Northwest Alberta 894 745.2 252 149.9 1,146 895.1 Northern Plains 2,619 2,148.4 5,029 4,457.4 7,648 6,605.8 Southern Plains 4,184 3,557.1 1,832 1,705.8 6,016 5,262.9 Southeast Saskatchewan -- -- 991 752.2 991 752.2 Non - core regions 738 107.5 301 160.6 1,039 268.1 United States 4 0.5 2 0.2 6 0.7 North Sea 2 0.1 106 88.5 108 88.6 Offshore West Africa Cote d'Ivoire -- -- 5 2.9 5 2.9 Angola -- -- -- -- -- -- ----- ------- ----- ------- ------ -------- Total 9,378 7,374.8 8,691 7,453.1 18,069 14,827.9 ----- ------- ----- ------- ------ --------
All reserves data in the following property report was based on the applicable independent engineering report. See below "Crude Oil and Natural Gas Reserves". Northeast British Columbia [GRAPHIC] This region comprises lands from Fort St. John, British Columbia to the northern border as well as the eastern border of British Columbia. Similar geological attributes extend throughout the region, producing light crude oil, natural gas liquids and natural gas. The Company holds working interests ranging up to 100 per cent and averaging 74 per cent in 3,799,223 gross (2,812,965 net) acres of producing and undeveloped land in the region. 19 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 2,500 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. Natural gas production from the region averaged 437.3 million cubic feet per day for 2004 compared to the average of 372.3 million cubic feet per day produced for 2003. Crude oil and natural gas liquids production was steady at to 6.8 thousand barrels per day in 2004 from an average of 6.7 thousand barrels per day in 2003. 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. In May of 2004 the Company acquired additional lands, facilities and production in the area. 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 has resulted in 30 to 50 wells being drilled in the area each year. During 2004, 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 up to 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 2004 the Company drilled 3.6 (2003- 5.1) net oil wells, 167.0 (2003 - 78.2) net natural gas wells, 1.0 (2003 - 0) net stratigraphic/service wells and 20.6 (2003 - 22.4) net dry wells on its lands in this region for a total of 192.2 (2003 - 105.7) net wells. The Company held an average 92.9 per cent working interest in these wells. 20 Northwest Alberta [GRAPHIC] The Company holds working interests ranging up to 100 per cent and averaging 76 per cent in 2,865,122 gross (2,166,652 net) acres of producing and undeveloped land in the region located along the border of British Columbia and Alberta west 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 700 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. Natural gas production from the region averaged 303.2 million cubic feet per day for 2004 compared to an average of 261.3 million cubic feet per day for 2003. Crude oil and natural gas liquids production was steady at 10.9 thousand barrels per day in 2004 from 11.1 thousand barrels per day in 2003. During 2004 the Company drilled 5.8 (2003-3.7) net oil wells, 137.5 (2003-97.9) net natural gas wells, 1.5 (2003 - 0) net stratigraphic/service wells, and 11.5 (2003-19.7) net dry wells on its lands in this region for a total of 156.3 (2003-121.3) net wells. The Company held an average 82.6 per cent working interest in these wells. 21 Northern Plains [GRAPHIC] The Company holds working interests ranging up to 100 per cent and averaging 82 per cent in 11,829,563 gross (9,667,926 net) acres of producing and undeveloped land in the region located just south of Edmonton north to Fort McMurray and from the northwest Alberta border 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 crude 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 429.9 million cubic feet per day in 2004 compared to 462.4 million cubic feet per day in 2003. Crude oil and natural gas liquids production from this region increased to 166.3 thousand barrels per day in 2004 from 136.7 thousand barrels per day in 2003. Production of natural gas was impacted by the shut-in effective July 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 crude oil (averaging 12 DEG.-14 DEG. 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 crude oil to the wellbore in this type of heavy oil reservoir comes from solution gas. The crude 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 of the original oil in place. A key component to maintaining profitability in the production of heavy crude 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. In the area around Elk Point, 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 22 operated Beartrap field during 2001, enhancing further development of the Company's extensive holdings in the area. This pipeline was 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 permits the Company to transport approximately 80 per cent of its heavy crude 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 crude oil. On February 18, 2004 the Company purchased the Petrovera Partnership which added additional properties in this region. Approximately one third of the total acquisition was sold to another independent producer. The properties that were retained further consolidated the Company's position in the area. Production from the 100% owned Primrose and Wolf Lake fields located near Bonnyville, Alberta involve processes that utilize steam to increase the recovery of the oil. The two processes employed by the Company are cyclic steam stimulation and Steam Assisted Gravity Drainage ("SAGD"). Both recovery processes inject steam to heat the heavy crude 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 58 high-pressure wells in 2004. Additional development of the leases will be undertaken in phases over the next several years. The Company in 2004 started to proceed with its Primrose North expansion project which is expected to be completed by November 2005. The Primrose North expansion entails a remote steam treating facility and additional high pressure wells which are expected to be on production in 2006. 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 approximately 100 per cent owned holdings at Pelican Lake. These lands contain reserves of 14 DEG.-17 DEG. API heavy oil. Operating costs are low due to no sand production or disposal requirements and the gathering and pipeline facilities in place. 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. The Company holds and controls approximately 75 percent 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 percent recovery factor using existing primary technologies on the Company's developed leases. Hence, in 2002 the Company embarked upon an Enhanced Oil Recovery 23 ("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. The implementation plan will result in the conversion of existing producing wells into water injectors and the drilling of additional producing wells. The Company will also examine opportunities to use polymer flooding in conjunction with waterflooding to obtain the highest recovery factor while maximizing value. This pilot is expected to commence in the second quarter of 2005. During 2004, the Company drilled 287.0 (2003 - 405.7) net oil wells, 163.4 (2003 - - 183.4) net natural gas wells, 112.0 (2003 - 63.5) net stratigraphic/service wells, and 49.8 (2003 - 64.5) net wells dry wells for a total of 612.2 (2003 - 717.1) net wells. The Company's average working interest in these wells was 91.4 per cent. Southern Plains and Southeast Saskatchewan [GRAPHIC] In the Southern Plains area, the Company holds interests ranging up to 100 per cent and averaging 82 per cent in 1,771,346 gross (1,451,816 net) acres of producing and undeveloped land in the region principally located south of the Northern Plains area to the United States border and to the east bounded by the Alberta-Saskatchewan border. 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 24 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 in the Southern Plains area averaged 12.7 (2003 - 10.9) thousand barrels of crude oil and natural gas liquids per day and 155.5 (2003- 141.9) million cubic feet of natural gas per day in 2004. During 2004, the Company drilled a total of 7.8 (2003 - 4.4) net oil wells, 220.6 (2003 - 416.5) net natural gas wells, 1.0 (2003 - 0.0) net stratigraphic/service well and 11.0 (2003 - 9.0) net dry wells in this region for a total of 240.4 (2003 - 429.9) net wells. The Company's average working interest in these wells was 86.5 per cent. The Williston Basin is located in Southeastern Saskatchewan with lands extending into Manitoba. This region 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 80 per cent in 246,304 gross (196,200 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. The Company's share of production in the Southeast Saskatchewan area averaged 9.3 (2003 - 9.2) thousand barrels of crude oil and natural gas liquids per day and 3.1 (2003- 3.4) million cubic feet of natural gas per day in 2004. The Company drilled 12.5 (2003 - 26.9) net oil wells with 0.0 (2003 - 0.0) net dry wells in this region in 2004, for a total of 12.5 (2003 - 26.9) net wells. The Company's average working interest in these wells is 65.9 per cent. United Kingdom North Sea [GRAPHIC] 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 876,422 gross (657,802 net) acres of producing and non-producing properties in the UK sector of the North Sea. In 2004, the Company produced from 15 crude oil fields. 25 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 Terraces 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. 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. In 2004 the Company acquired 100 per cent working interest in T-block (comprising the Tiffany, Toni and Thelma Fields) and 68.7 per cent to 75.3 per cent interests in the Fields known as B-block (comprising Balmoral, Stirling and Glamis). The Company took over as operator of these fields. The Company also owns a 45.7 per cent operated working interest in the Kyle Field. 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 processing of crude oil and natural gas through some of the processing facilities. Opportunities for further long-reach well development on adjacent fields are provided from the existing processing facilities. During 2004, production to the Company from this region averaged 64.7 (2003 - 56.9) thousand barrels of crude oil per day and 50.4 (2003 - 45.6) million cubic feet of natural gas per day. The Company drilled 9.2 (2003 - 11.1) net oil wells, 2.7 (2003 - 4.8) net service wells and 2.0 (2003 - 1.8) net dry wells in 2004 in this region for a total of 13.9 (2003 - 17.7) net wells. The Company's average working interest in these wells is 92.3 per cent. Offshore West Africa [GRAPHIC] 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 1,589,213 gross 26 (885,541 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 275,625 net acres. During 2001, the Company increased its interest in Block CI-26, which contains the Espoir 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 first phase of 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 an infill drilling program in East Espoir and development plans for the West Espoir part of the Field were completed in 2004. Oil from the East Espoir is produced into an FPSO with associated natural gas delivered onshore through a subsea pipeline for local power generation. In 2003 the Company drilled a satellite pool, Acajou, which encountered a reservoir with good quality and hydrocarbons. The extent of this accumulation was further appraised by a well drilled in 2004 which did not encounter commercial hydrocarbons. 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 and is progressing according to plan towards first oil in 2005. 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 2004, net daily production to the Company averaged 11.6 (2003 - 10.6) thousand barrels of crude oil and 7.5 (2003 - 8.4) million cubic feet of natural gas. In 2004, the Company drilled 2.3 (2003 - 1.3) net oil wells, 0.0 (2003 - 2.0) net service wells and 0.7 (2003 - 0.0) net dry wells for a total of 3.0 (2003 - 3.3) net wells. The Company's average working interest in these wells is 59.3 per cent. Angola During 2002, the Company was awarded operatorship and a 50 per cent working interest in exploration Block 16 situated offshore The People's Republic of Angola. 3-D seismic was obtained 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. Following further evaluation of seismic and the well results during 2004, the Company is considering various options, including divestment. 27 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. 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, which has two aspects; namely, bitumen production and bitumen upgrading to SCO, is designed as a phased development. Site clearing and pre-construction preparation activities commenced in 2004 and construction will 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 estimated capital costs of the phased development are $10.8 billion, of which approximately $6.8 billion including contingency funding of $700 million would be required for Phase 1. When the Horizon Project is fully commissioned, operating costs - including sustaining capital - are expected to be in the range of $14 per barrel. Canadian Natural filed an application for regulatory approval of the Horizon Project in June 2002. The application included a comprehensive environmental impact assessment, 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. An Alberta Order-in-Council approval was received in February 2004. Subsequently, key approvals were received from Alberta Environment under the Environmental Protection Act and Water Act, and from Fisheries and Oceans Canada under the Fisheries Act. 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. 28 Canadian Natural used 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 and final front-end engineering phase, completing the work in December 2004. The products of this phase include a detailed project execution plan, Engineering Design Specifications ("EDS") and a detailed cost estimate (plus or minus 10%). The EDS provided sufficient definition for a lump sum inquiry for the Detailed Engineering, Procurement and Construction of the various project components. With this information a "cost certainty" estimate was developed as a basis for project sanction by the Board of Directors which was given in February 2005 authorizing management to proceed with Phase 1 of the Horizon Oil Sands Project. Horizon is designed to use proven technology and will seek to take advantage of technology improvements that advance environmental performance, enhance the work environment for workers, increase reliability and production and reduce capital and operating costs. By the end of 2004 the Company had acquired all key technologies for the project. At year end, Horizon Project staff, including direct hire and contract, representing the many skill disciplines required to define and implement the project numbered 800, about 75% of the required staff compliment to implement Phase 1. Canadian Natural expended $291 million on the Horizon Project in 2004. Cumulative expenditures on the project are $672 million to the end of 2004. These expenditures include lease evaluation, engineering definition, technology acquisition, environmental and socio-economic assessment, public consultation, regulatory application, completion of road infrastructure to the site and preliminary site development. Capital expenditures for 2005 are budgeted to be $1.4 billion reflecting the beginning of major expenditures for detailed engineering, procurement and construction of Phase 1 of the Project. During 2004, the Company drilled 218 (2003 - 370) stratigraphic test wells to further delineate the ore body and confirm resource quality and quantity. B. CRUDE OIL AND NATURAL GAS RESERVES The Company retains independent qualified petroleum engineering consultants Sproule Associates Limited ("Sproule") and Ryder Scott Company ("Ryder Scott") 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 Evaluation Reports are effective December 31, 2004 as prepared February 18, 2005. 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 29 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 each of Sproule and Ryder Scott and carried out the appropriate independent due diligence procedures with Sproule and Ryder Scott to review the qualifications of and procedures used by Sproule and Ryder Scott 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, 2004. 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 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 648 926 2,590 3,317 United States 0 0 1 2 International United Kingdom 303 415 27 57 Cote d'Ivoire 115 196 72 90 ----- ----- ----- ----- Total 1,066 1,537 2,690 3,466 ===== ===== ===== ===== 30 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 638 605 2,761 2,230 Proved undeveloped 485 461 549 460 ----- ----- ----- ----- Total proved reserves 1,123 1,066 3,310 2,690 Total proved and probable reserves 1,621 1,537 4,259 3,466 ===== ===== ===== ===== Estimated Future Net Revenues Constant Prices and Costs --------------------------------------- ($ Millions) Undiscounted Discounted at ------------ ------------------------ 10% 15% 20% ------ ------ ------ Proved developed 21,092 13,739 11,838 10,453 Proved undeveloped 8,059 4,399 3,440 2,748 ------ ------ ------ ------ Total proved reserves 29,151 18,138 15,279 13,201 Total proved and probable reserves 40,088 22,937 18,802 15,899 ====== ====== ====== ====== Crude Oil, NGL and Natural Gas Reserves Forecast Prices and Costs ----------------------------------------- Crude Oil and Natural Gas Liquids (MMbbls) Natural Gas (Bcf) --------------------- ----------------- Gross Net Gross Net --------- --------- ------- ------- Proved developed 627 582 2,702 2,179 Proved undeveloped 487 451 545 456 ----- ----- ----- ----- Total proved reserves 1,114 1,033 3,247 2,635 Total proved and probable reserves 1,617 1,501 4,178 3,394 ===== ===== ===== ===== Estimated Future Net Revenues Forecast Prices and Costs --------------------------------------- ($ Millions) Undiscounted Discounted at ------------ ------------------------ 10% 15% 20% ------ ------ ------ Proved developed 17,838 12,708 11,267 10,181 Proved undeveloped 7,856 4,071 3,164 2,528 ------ ------ ------ ------ Total proved reserves 25,694 16,779 14,431 12,709 Total proved and probable reserves 35,579 20,985 17,515 15,080 ====== ====== ====== ====== 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. 31 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-jurisdictional 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. 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 2004 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 ----------------------------------------------- ----------------------------------------------------------- Company Company Hardisty Average Henry Hub Huntingdon/ Average WTI @ Heavy Edmonton North Sea Price Louisiana AECO Sumas Price Cushing (i) 12 DEG. API Par (ii) Brent YEAR $CDN/Mcf $US/MMBtu $CDN/MMBtu $CDN/MMBtu $CDN/bbl $US/bbl $CDN/bbl $CDN/bbl $US/bbl - ---- -------- --------- ---------- ----------- -------- ----------- ----------- -------- --------- 2004 6.44 6.62(iii) 6.78 6.94 32.14 44.04(iv) 17.45 51.62 40.47
(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 (40 DEG. API), low sulphur content crude oil at Edmonton, Alberta. (iii)There was no trading of Henry Hub on December 31, 2004. This posted value was determined on the basis of December 30, 2004 posted price for Henry Hub adjusted for the change in the AECO price as posted by the Canadian Gas Price Reporter. (iv) There was no trading on WTI on December 31, 2004. This posted value was determined on the basis of December 30, 2004 posted price for WTI adjusted for the change in the Brent price as posted by the Platts Oilgram Price Report. (v) Foreign exchange rate used was $0.832 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 transportation. 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, 2005 crude oil, natural gas liquids and natural gas pricing model. 32 The Company's weighted average crude oil and NGLs price and the weighted average natural gas price in 2004 were $37.99 per barrel and $6.50 per mcf respectively, before adjustments due to hedging. The crude oil and natural gas forecast prices used in the Evaluation Reports are as follows: - --------------------------------------------------------------------------------
NATURAL GAS CRUDE OIL & NGLs ----------------------------------------------- ------------------------------------------------------- Company Company Hardisty Average Henry Hub Huntingdon/ Average WTI @ Heavy Edmonton North Sea Price Louisiana AECO Sumas Price Cushing 12 DEG. API Par Brent YEAR $CDN/Mcf $US/MMBtu $CDN/MMBtu $CDN/MMBtu $CDN/bbl $US/bbl $CDN/bbl $CDN/bbl $US/bbl - ---- -------- --------- ---------- ----------- -------- ------- ----------- -------- --------- 2005 6.63 6.74 6.97 7.13 38.50 44.29 28.91 51.25 42.79 2006 6.31 6.48 6.66 6.92 36.80 41.60 28.12 48.03 40.08 2007 5.84 6.08 6.21 6.47 33.66 37.09 26.19 42.64 34.54 2008 5.36 5.70 5.73 5.99 31.04 33.46 25.06 38.31 31.89 2009 5.01 5.41 5.37 5.63 29.04 31.84 23.60 36.36 30.25 2010 5.10 5.49 5.47 5.73 29.53 32.32 24.12 36.91 30.70 2011 5.24 5.58 5.57 5.83 30.33 32.80 24.64 37.47 31.16 2012 5.32 5.66 5.67 5.93 29.74 33.30 25.17 38.03 31.63 2013 5.40 5.75 5.77 6.03 29.76 33.79 25.71 38.61 32.11 2014 5.49 5.83 5.87 6.13 30.29 34.30 26.26 39.19 32.59 2015 5.59 5.92 5.98 6.24 30.21 34.82 26.82 39.78 33.08
(i) Foreign exchange rate used was $0.84 US / $1.00 Cdn throughout the forecast 11. Estimated future net revenue from all assets is income derived from the sale of net reserves of crude oil, natural gas and natural gas liquids, less all capital costs, production taxes, and operating costs and before provision for income taxes, administrative overhead costs and existing asset abandonment liabilities. 12. The estimated total development capital costs net to the Company necessary to achieve the estimated future net "proved" and "proved and probable" production revenues are: PROVED PROVED AND PROBABLE ------------------------------------------------------------------ FORECAST PRICE CONSTANT PRICE FORECAST PRICE CONSTANT PRICE CASE CASE CASE CASE ($Millions) ($Millions) ($Millions) ($Millions) -------------- -------------- -------------- --------------- 2005 1,331 1,325 1,465 1,458 2006 541 534 633 621 2007 302 292 472 438 2008 212 199 535 497 2009 133 123 486 452 2010 129 117 402 367 2011 164 305 415 438 2012 81 97 229 151 2013 37 81 171 175 2014 213 62 49 79 2015 120 36 160 46 2016 90 80 54 83 Thereafter 561 460 825 634 13. 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 conventional reserves data by Sproule and Ryder Scott 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. 33 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, 2003 588 222 85 895 2,426 62 64 2552 Extensions & Discoveries 17 0 0 17 334 0 0 334 Infill Drilling 24 35 0 59 74 0 0 74 Improved Recovery 1 10 0 11 6 0 0 6 Property purchases 36 38 0 74 182 10 0 192 Property disposals 0 0 0 0 (8) 0 0 (8) Production (66) (24) (4) (94) (383) (18) (3) (404) Revisions of prior estimates 48 22 34 104 (40) (27) 11 (56) --- --- --- ----- ----- --- --- ---- Reserves, December 31, 2004 648 303 115 1,066 2591 27 72 2690 --- --- --- ----- ----- --- --- ---- Proved + Probable reserves Reserves, December 31, 2003 857 317 133 1,307 2919 102 72 3093 Extensions & Discoveries 20 0 0 20 418 0 0 418 Infill Drilling 29 49 0 78 106 0 0 106 Improved Recovery 2 10 0 12 6 0 0 6 Property purchases 49 49 0 98 236 18 0 254 Property disposals 0 0 0 0 (10) 0 0 (10) Production (66) (24) (4) (94) (383) (18) (3) (404) Revisions of prior estimates 35 14 67 116 27 (45) 21 3 --- --- --- ----- ----- --- --- ---- Reserves, December 31, 2004 926 415 196 1,537 3319 57 90 3466
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 2004 Annual Report under "Supplementary Oil and Gas Information" on pages 91 to 95 and is incorporated herein by reference. 34 D. OIL SANDS MINING RESERVES Horizon oil sands mining reserves are not part of Canadian Natural's year-end reserves disclosure. Horizon reserves were evaluated as of February 9, 2005, as reported in their report dated February 18, 2004, with the authorization by the Board of Directors to proceed with Phase 1 of the Horizon Oil Sands Project (the "Horizon Project"). Gilbert Laustsen Jung Associates Ltd. ("GLJ"), a qualified independent reserves evaluator, was retained by the Reserves Committee of Canadian Natural's Board of Directors to evaluate reserves associated with the Horizon Project incorporating both the mining and upgrading projects. These reserves were evaluated under SEC Industry Guide 7. The Reserves Committee has met with GLJ and carried out independent due diligence procedures with GLJ as to the Company's Horizon Project reserves. The following table sets out, on a gross basis, Canadian Natural's proved and probable reserves of bitumen and synthetic crude oil from its Oil Sands mining leases as of February 9, 2005. Gross Oil Sands Mining Reserves (MMbbls) ---------------------------------------- Proved Probable Proved and Probable ------ -------- ------------------- Bitumen 1,900 1,420 3,320 Synthetic crude oil (1) 1,560 1,230 2,790 (1) Synthetic crude oil reserves are based on upgrading of the bitumen reserves. The reserves shown for bitumen and synthetic crude oil are not additive. A report on Horizon oil sands mining reserves data by GLJ and a report of the Company's management and directors on mining reserves 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 and mining reserves with any U. S. agency or federal authority other than the SEC. E. 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 --------------------------- 2004 2003 2002 ------- ------- ------- Daily Production Crude Oil and NGLs (bbls/d) 282,489 242,392 215,335 Natural Gas (MMcf/d) 1,388 1,299 1,232 Annual Production Crude Oil and NGLs (Mbbls) 103,391 88,473 78,597 Natural Gas (Bcf) 508 474 450 35 NETBACKS INFORMATION BY QUARTER
YEAR 2004 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- Average Daily Production Volumes Crude oil and NGL's (bbl) 261,286 275,398 297,262 295,704 282,489 Natural Gas (mcf) 1,294 1,452 1,396 1,410 1,388 Product Netbacks Crude oil and NGLs ($/bbl) Sales Price (1) $ 34.21 $ 36.72 $ 43.50 $ 36.92 $ 37.99 Royalties $ 2.91 $ 3.15 $ 3.59 $ 2.95 $ 3.16 Production Expenses $ 9.58 $ 9.92 $ 10.21 $ 10.41 $ 10.05 Netback $ 21.72 $ 23.65 $ 29.70 $ 23.56 $ 24.78 Natural Gas ($/Mcf) Sales Price (1) $ 6.31 $ 6.64 $ 6.24 $ 6.77 $ 6.50 Royalties $ 1.27 $ 1.38 $ 1.39 $ 1.34 $ 1.35 Production Expenses $ 0.65 $ 0.66 $ 0.71 $ 0.68 $ 0.67 Netback $ 4.39 $ 4.60 $ 4.14 $ 4.75 $ 4.48 Crude Oil and NGL Netbacks by Type Light/Pelican Lake/NGLs ($/bbl) Sales Price (1) $ 40.75 $ 45.28 $ 51.54 $ 48.60 $ 46.71 Royalties $ 3.71 $ 3.98 $ 3.99 $ 4.12 $ 3.95 Production Expenses $ 9.77 $ 10.36 $ 10.70 $ 11.20 $ 10.53 Netback $ 27.27 $ 30.94 $ 36.85 $ 33.28 $ 32.23 Heavy ($/bbl) Sales Price (1) $ 27.00 $ 28.08 $ 35.33 $ 25.16 $ 28.99 Royalties $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34 Production Expenses $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56 Netback $ 15.60 $ 16.30 $ 22.43 $ 13.77 $ 17.09 YEAR 2003 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- Average Daily Production Volumes Crude oil and NGL's (bbl) 237,560 240,607 247,016 244,262 242,392 Natural Gas (mcf) 1,310 1,325 1,289 1,270 1,299 Product Netbacks Crude oil and NGLs ($/bbl) Sales Price (1) $ 39.37 $ 30.66 $ 31.45 $ 29.47 $ 32.66 Royalties $ 3.56 $ 2.78 $ 2.56 $ 2.22 $ 2.77 Production Expenses $ 10.79 $ 10.80 $ 10.14 $ 9.45 $ 10.28 Netback $ 25.02 $ 17.08 $ 18.75 $ 17.80 $ 19.61 Natural Gas ($/Mcf) Sales Price (1) $ 7.75 $ 6.25 $ 5.57 $ 5.26 $ 6.21 Royalties $ 1.78 $ 1.35 $ 1.11 $ 1.05 $ 1.32 Production Expenses $ 0.57 $ 0.59 $ 0.63 $ 0.63 $ 0.60 Netback $ 5.40 $ 4.31 $ 3.83 $ 3.58 $ 4.29 Crude Oil and NGL Netbacks by Type Light/Pelican Lake/NGLs ($/bbl) Sales Price (1) $ 44.38 $ 34.60 $ 36.06 $ 35.76 $ 37.66 Royalties $ 4.18 $ 3.32 $ 3.11 $ 2.82 $ 3.35 Production Expenses $ 10.42 $ 9.76 $ 9.53 $ 9.65 $ 9.83 Netback $ 29.78 $ 21.52 $ 23.42 $ 23.29 $ 24.48 Heavy ($/bbl) Sales Price (1) $ 32.44 $ 25.37 $ 25.17 $ 21.45 $ 25.98 Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00 Production Expenses $ 11.30 $ 12.19 $ 10.96 $ 9.19 $ 10.88 Netback $ 18.43 $ 11.12 $ 12.38 $ 10.79 $ 13.10
NOTE: Pelican Lake oil has an API of 14 DEG. to 17 DEG., but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. (1) Including transportation and excluding risk management activities 36 NETBACKS INFORMATION BY QUARTER
YEAR 2004 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- SEGMENTED North America Product Netbacks Light/Pelican Lake/NGLs ($/bbl) Sales Price (1) $37.54 $41.03 $44.89 $43.80 $41.81 Royalties $ 7.20 $ 7.91 $ 8.59 $ 8.76 $ 8.12 Production Expenses $ 7.30 $ 7.74 $ 7.75 $ 7.85 $ 7.66 Netback $23.04 $25.38 $28.55 $27.19 $26.03 Heavy ($/bbl) Sales Price (1) $27.00 $28.08 $35.33 $25.16 $28.99 Royalties $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34 Production Expenses $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56 Netback $15.60 $16.30 $22.43 $13.77 $17.09 Natural Gas ($/Mcf) Sales Price (1) $ 6.37 $ 6.78 $ 6.36 $ 6.88 $ 6.61 Royalties $ 1.33 $ 1.44 $ 1.45 $ 1.39 $ 1.40 Production Expenses $ 0.60 $ 0.60 $ 0.63 $ 0.63 $ 0.62 Netback $ 4.44 $ 4.74 $ 4.28 $ 4.86 $ 4.59 North Sea Product Netbacks Light Oil ($/bbl) Sales Price (1) $44.27 $49.22 $57.39 $52.77 $51.37 Royalties $ 0.06 $ 0.10 $ 0.09 $ 0.08 $ 0.08 Production Expenses $13.26 $13.84 $13.88 $14.96 $14.03 Netback $30.95 $35.28 $43.42 $37.73 $37.26 Natural Gas ($/Mcf) Sales Price (1) $ 5.08 $ 3.28 $ 3.17 $ 3.26 $ 3.73 Royalties $ -- $ -- $ -- $ -- $ -- Production Expenses $ 1.65 $ 1.92 $ 2.48 $ 2.29 $ 2.07 Netback $ 3.43 $ 1.36 $ 0.69 $ 0.97 $ 1.66 Offshore West Africa Product Netbacks Light Oil ($/bbl) Sales Price (1) $42.08 $49.34 $53.86 $51.28 $49.05 Royalties $ 1.28 $ 1.52 $ 1.42 $ 1.52 $ 1.43 Production Expenses $ 7.09 $ 7.43 $ 8.05 $ 7.82 $ 7.59 Netback $33.71 $40.39 $44.39 $41.94 $40.03 Natural Gas ($/Mcf) Sales Price (1) $ 4.80 $ 5.18 $ 6.31 $ 4.73 $ 5.25 Royalties $ 0.15 $ 0.16 $ 0.17 $ 0.14 $ 0.15 Production Expenses $ 1.23 $ 1.38 $ 1.39 $ 1.31 $ 1.33 Netback $ 3.42 $ 3.64 $ 4.75 $ 3.28 $ 3.77 YEAR 2003 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- SEGMENTED North America Product Netbacks Light/Pelican Lake/NGLs ($/bbl) Sales Price (1) $40.89 $32.73 $32.78 $30.95 $34.37 Royalties $ 7.65 $ 6.33 $ 6.04 $ 5.51 $ 6.39 Production Expenses $ 6.09 $ 6.42 $ 6.76 $ 7.24 $ 6.62 Netback $27.15 $19.98 $19.98 $18.20 $21.36 Heavy ($/bbl) Sales Price (1) $32.44 $25.37 $25.17 $21.45 $25.98 Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00 Production Expenses $11.30 $12.19 $10.96 $ 9.19 $10.88 Netback $18.43 $11.12 $12.38 $10.79 $13.10 Natural Gas ($/Mcf) Sales Price (1) $ 7.88 $ 6.39 $ 5.70 $ 5.35 $ 6.34 Royalties $ 1.84 $ 1.40 $ 1.16 $ 1.10 $ 1.38 Production Expenses $ 0.55 $ 0.56 $ 0.58 $ 0.60 $ 0.57 Netback $ 5.49 $ 4.43 $ 3.96 $ 3.65 $ 4.39 North Sea Product Netbacks Light Oil ($/bbl) Sales Price (1) $49.74 $37.08 $39.63 $41.70 $42.00 Royalties $ 0.11 $(0.19) $ 0.09 $(0.15) $(0.03) Production Expenses $15.50 $14.17 $13.25 $13.42 $14.07 Netback $34.13 $23.10 $26.29 $28.43 $27.96 Natural Gas ($/Mcf) Sales Price (1) $ 4.03 $ 2.21 $ 2.57 $ 3.32 $ 3.03 Royalties $ -- $ -- $ -- $ -- $ -- Production Expenses $ 1.09 $ 1.45 $ 1.60 $ 1.16 $ 1.33 Netback $ 2.94 $ 0.76 $ 0.97 $ 2.16 $ 1.70 Offshore West Africa Product Netbacks Light Oil ($/bbl) Sales Price (1) $37.86 $34.34 $37.37 $36.42 $36.47 Royalties $ 1.20 $ 0.99 $ 1.13 $ 1.03 $ 1.08 Production Expenses $14.03 $ 9.32 $ 7.11 $ 6.67 $ 8.68 Netback $22.63 $24.03 $29.13 $28.72 $26.71 Natural Gas ($/Mcf) Sales Price (1) $ 3.80 $ 5.09 $ 4.58 $ 3.95 $ 4.37 Royalties $ 0.11 $ 0.15 $ 0.14 $ 0.11 $ 0.13 Production Expenses $ 2.37 $ 1.45 $ 1.24 $ 1.18 $ 1.39 Netback $ 1.32 $ 3.49 $ 3.20 $ 2.66 $ 2.85
NOTE: Pelican Lake oil has an API of 14 DEG. to 17 DEG., but receives medium qualitycrude netbacks due to exceptionally low operating costs and low royalty rates. (1) Including transportation and excluding risk management activities 37 NETBACKS INFORMATION BY QUARTER
YEAR 2002 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- Average Daily Production Volumes Crude Oil and NGLs (bbls) 188,439 189,386 242,051 240,596 215,335 Natural Gas (Mcf) 1,053 1,078 1,427 1,365 1,232 Product Netbacks Crude oil and NGLs ($/bbl) Sales Price (1) $ 25.00 $ 30.12 $ 35.19 $ 32.83 $ 31.22 Royalties $ 2.28 $ 3.02 $ 3.56 $ 3.53 $ 3.16 Production Expenses $ 7.81 $ 7.95 $ 8.67 $ 9.10 $ 8.45 Netback $ 14.91 $ 19.15 $ 22.96 $ 20.20 $ 19.61 Natural Gas ($/Mcf) Sales Price (1) $ 2.98 $ 3.77 $ 3.08 $ 5.07 $ 3.77 Royalties $ 0.55 $ 0.77 $ 0.67 $ 1.09 $ 0.78 Production Expenses $ 0.58 $ 0.57 $ 0.55 $ 0.57 $ 0.57 Netback $ 1.85 $ 2.43 $ 1.86 $ 3.41 $ 2.42 Crude Oil and NGL Netbacks by Type Light/Pelican Lake/NGLs ($/bbl) Sales Price (1) $ 29.09 $ 33.37 $ 38.05 $ 37.97 $ 35.16 Royalties $ 3.25 $ 4.04 $ 4.48 $ 4.39 $ 4.10 Production Expenses $ 7.48 $ 8.36 $ 10.06 $ 9.38 $ 8.97 Netback $ 18.36 $ 20.97 $ 23.51 $ 24.20 $ 22.09 Heavy ($/bbl) Sales Price (1) $ 20.49 $ 26.42 $ 31.59 $ 26.45 $ 26.52 Royalties $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03 Production Expenses $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84 Netback $ 11.10 $ 17.08 $ 22.26 $ 15.23 $ 16.65
SEGMENTED North America Product Netbacks
YEAR 2002 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- Light/Pelican Lake/NGLs ($/bbl) Sales Price (1) $25.75 $31.10 $35.01 $34.34 $31.88 Royalties $ 4.24 $ 5.11 $ 5.98 $ 5.81 $ 5.35 Production Expenses $ 5.25 $ 5.30 $ 5.00 $ 5.28 $ 5.20 Netback $16.26 $20.69 $24.03 $23.25 $21.33 Heavy ($/bbl) Sales Price (1) $20.49 $26.42 $31.59 $26.45 $26.52 Royalties $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03 Production Expenses $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84 Netback $11.10 $17.08 $22.26 $15.23 $16.65 Natural Gas ($/Mcf) Sales Price (1) $ 2.96 $ 3.81 $ 3.10 $ 5.11 $ 3.79 Royalties $ 0.57 $ 0.79 $ 0.69 $ 1.11 $ 0.80 Production Expenses $ 0.56 $ 0.55 $ 0.52 $ 0.55 $ 0.55 Netback $ 1.83 $ 2.47 $ 1.89 $ 3.45 $ 2.44 North Sea Product Netbacks Light Oil ($/bbl) Sales Price (1) $34.43 $39.43 $42.24 $42.46 $40.32 Royalties $ 1.54 $ 1.76 $ 2.56 $ 2.79 $ 2.30 Production Expenses $10.09 $15.72 $18.30 $14.68 $15.06 Netback $22.80 $21.95 $21.38 $24.99 $22.96 Natural Gas ($/Mcf) Sales Price (1) $ 3.77 $ 1.80 $ 1.98 $ 3.20 $ 2.75 Royalties -- -- -- -- -- Production Expenses $ 1.33 $ 1.90 $ 1.78 $ 1.25 $ 1.53 Netback $ 2.44 ($0.10) $ 0.20 $ 1.95 $ 1.22
38 Offshore West Africa Product Netbacks
YEAR 2002 ------------------------------------------------------------------ 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended ----------- ----------- ----------- ----------- ---------- Light Oil ($/bbl) Sales Price (1) $37.61 $33.92 $42.78 $43.15 $40.10 Royalties $ 1.65 $ 1.11 $ 1.34 $ 1.35 $ 1.35 Production Expenses $18.62 $12.76 $11.23 $13.68 $13.63 Netback $17.34 $20.05 $30.21 $28.12 $25.12 Natural Gas ($/Mcf) Sales Price (1) -- -- $ 4.97 $ 4.63 $ 4.82 Royalties -- -- $ 0.15 $ 0.15 $ 0.15 Production Expenses -- -- $ 1.77 $ 1.85 $ 1.81 Netback $ -- $ -- $ 3.05 $ 2.63 $ 2.86
1) Including transportation and excluding risk management activities F. 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 ---------------------------- 2004 2003 ------------ ------------- Gross Net Gross Net ----- ---- ----- ----- Natural Gas 801 689 841 777 Crude Oil 378 328 490 458 Service/Stratigraphic 339 336 447 440 Dry Holes 106 96 126 118 ---- ---- ----- ----- Total 1624 1449 1,904 1,793 ==== ==== ===== ===== *Total Success Rate 91% 91% *excluding service and stratigraphic test wells 39 G. 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 ------------- 2004 2003 ----- ----- Net property acquisitions(1) 1,835 336 Land acquisition and retention 120 154 Seismic evaluation 89 77 Well drilling, completion and equipping 1,394 1,194 Pipeline and production facilities 821 522 ----- ----- Reserve replacement expenditures 4,259 2,283 Midstream operations 16 11 Horizon Project 291 152 Abandonments 32 40 Head office equipment 35 20 ----- ----- Total Net Capital Expenditures 4,633 2,506 ===== ===== (1) Includes Business Combinations 40 2004 THREE MONTHS ENDED -------------------------------------- ($ Millions) CAPITAL EXPENDITURES BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ------- ------- -------- ------- Net property acquisitions(1) 507 277 290 761 Land acquisition and retention 31 39 37 13 Seismic evaluation 32 11 25 21 Well drilling, completion and equipping 583 231 221 359 Pipeline and production facilities 280 166 190 185 ----- --- --- ----- Reserve replacement expenditures 1,433 724 763 1,339 Midstream operations -- 3 2 11 Horizon Project 46 103 84 58 Abandonments 7 6 14 5 Head office equipment 7 8 12 8 ----- --- --- ----- Total Net Capital Expenditures 1,493 844 875 1,421 ===== === === ===== (1) Includes Business Combinations 2003 THREE MONTHS ENDED -------------------------------------- ($ Millions) CAPITAL EXPENDITURES BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ------- ------- -------- ------- Net property acquisitions(1) 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 === === === === (1) Includes Business Combinations 41 H. NON-RESERVE ACREAGE The following table summarizes the Company's working interest holdings in core region non-reserve acreage as at December 31, 2004: Gross Acres Net Acres ----------- ----------- (thousands) (thousands) North America Alberta 10,869 9,032 British Columbia 2,436 1,824 Saskatchewan 738 659 Manitoba 8 7 North Sea United Kingdom 738 565 Offshore West Africa Angola 1,220 610 Cote d'Ivoire 369 276 South Africa 5,550 5,550 ------ ------ Total 21,928 18,523 ====== ====== I. DEVELOPED ACREAGE The following table summarizes the Company's working interest holdings in core region developed acreage as at December 31, 2004: Gross Acres Net Acres ----------- ----------- (thousands) (thousands) North America Alberta 5,350 3,960 British Columbia 895 682 Saskatchewan 326 242 Manitoba 6 5 North Sea United Kingdom 138 93 Offshore West Africa Cote d'Ivoire 8 5 ----- ----- Total 6,723 4,987 ===== ===== 42 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 ------------------------------------------ 2004 2003 ------ ------ ($ millions, except per share information) Revenues (1) (net of royalties) 6,536 5,283 Cash flow from operations 3,769 3,160 Per common share - basic 14.06 11.77 - diluted 13.98 11.53 Net earnings (4) 1,405 1,403 Per common share - basic 5.24 5.23 - diluted 5.20 5.06 Total assets (4) 18,410 14,643 Total long-term debt(2,3) 3,538 2,748 ------------------------------------------ 2004 THREE MONTHS ENDED ------------------------------------------ MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- ($ millions, except per share information) Revenues (1) (net of royalties) 1,420 1,603 1,799 1,714 Net earnings 258 259 311 577 Per common share - basic 1.92 0.97 1.16 2.15 - diluted 1.92 0.97 1.13 2.13 ------------------------------------------ 2003 THREE MONTHS ENDED ------------------------------------------ MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- ($ millions, except per share information) Revenues (1) (net of royalties) 1,554 1,279 1,264 1,186 Net earnings (4) 427 525 201 250 Per common share - basic 1.60 1.96 0.75 0.93 - diluted 1.52 1.89 0.74 0.91 (1) Excluding transportation costs and risk management activities. (2) Restated to include preferred securities (3) Excluding current portion of long-term debt. (4) Restated for asset retirement obligations 43 CAPITAL STRUCTURE Common Shares The Company is authorized to issue an unlimited number of common shares, without nominal or par value. Holders of common shares are entitled to one vote per share at a meeting of shareholders of Canadian Natural, to receive such dividends as declared by the Board of Directors on the common shares and to receive pro-rata the remaining property and assets of the Company upon its dissolution or winding up, subject to any rights having priority over the common shares. Preferred Shares The Company has no preferred shares outstanding, however, the Company is authorized to issue two-hundred thousand (200,000) preferred shares designated as Class 1 Preferred Shares. Holders of preferred shares shall not be entitled as such to receive notice of or to attend any meeting of the shareholders of the Company and shall not be entitled to vote at any such meeting except under certain circumstances as described in the Articles of Amalgamation. Holders of preferred shares are entitled to receive such dividends as and when declared by the Board of Directors in priority to common shares and shall be entitled to receive pro-rata in priority to holders of commons shares the remaining property and assets of Canadian Natural upon its dissolution or winding-up. The Company may redeem or purchase for cancellation at any time all or any part of the then outstanding preferred shares and the holders of the preferred shares shall have the right at any time and from time to time to convert such preferred shares into the common shares of the company. There are no preferred shares currently outstanding. Credit Ratings Credit ratings accorded to the Company's debt securities are not recommendations to purchase, hold or sell the debt securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant, and if any such rating is so revised or withdrawn. The Company's senior unsecured long-term debt securities are rated "Baa1" with a stable outlook by Moody's Investor Services, Inc. ("Moody's"), "BBB+" by Standard & Poor's Corporation ("S&P") and "BBB high" with a stable trend by Dominion Bond Rating Service Limited ("DBRS"). S&P assigns a "BBB-" rating to the Company's subordinated notes. S&P assigns a rating outlook to the Company and not to individual debt instruments. S&P has assigned a negative outlook to the Company. Debt Rated $125 CAD million 7.40% unsecured note due 2007 $400 US million 6.70% unsecured note due 2011 $400 US million 7.20% unsecured note due 2032 $350 US million 5.45% unsecured note due 2012 $350 US million 6.54% unsecured note due 2033 $125 US million 7.69% unsecured note due 2005 $93 US million 6.45% Adjustable rate note due 2009 $350 US million 4.90% unsecured note due 2014 $350 US million 5.85% unsecured note due 2035 $80 US million 8.30% subordinated note due 2011 44 Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. According to the Moody's rating system, debt securities rated Baa1 are considered as medium-grade obligations, i.e. they are neither highly protected nor poorly secured. Interest payments and principal security appear adequate for the present but certain protective elements may be lacking or may be characteristically unreliable over any great length of time. Such securities lack outstanding investment characteristics and in fact have speculative characteristics as well. Moody's applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa through Caa in its corporate bond rating system. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of its generic rating category. A Moody's rating outlook is an opinion regarding the likely direction of a rating over the medium term. S&P's credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. According to the S&P rating system, debt securities rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments on the notes. The ratings from AA to B may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. An S&P rating outlook assesses the potential direction of a long term credit rating over the intermediate to longer term. In determining a rating outlook, consideration is given to any changes in the economic and/or fundamental business conditions. DBRS' credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. According to the DBRS rating system, debt securities rated BBB are of adequate credit quality. Protection of interest and principal is considered acceptable, but the entity is fairly susceptible to adverse changes in financial and economic conditions. The assignment of a "(high)" or "(low)" modifier within each rating category indicates relative standing within such category. The "high" and "low" grades are not used for the AAA category. The rating trend is DBRS' opinion regarding the outlook for the rating. 45 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. 2004 Monthly Historical Trading on Toronto Stock Exchange Month High Low Close Volume Traded - ----- ------ ------ ------ ------------- January $71.80 $63.82 $64.00 12,121,445 February 73.85 63.99 73.25 9,749,239 March 76.50 70.20 72.70 12,853,959 April 81.65 72.85 75.40 12,279,432 May 1 - 18 81.70 73.80 78.55 8,416,911 *May 19 - 31 39.40 35.08 37.00 12,306,037 June 41.15 35.26 40.05 27,235,021 July 44.27 39.75 44.25 16,359,717 August 45.45 40.52 42.71 22,497,977 September 51.04 41.75 50.50 26,159,733 October 55.15 48.61 51.28 27,437,454 November 52.33 45.90 51.03 31,361,601 December 51.90 45.50 51.25 28,812,709 * Shares began trading on a post two-for-one subdivision basis on May 19, 2004. 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. Under this program, the Company purchased a total of 873,400 common shares for cancellation at an average purchase price of $37.98 for each common share purchased; $38.01 after costs. 46 At the Annual and Special Meeting of Shareholders held May 6, 2004, the shareholders passed a special resolution amending the Articles of the Company to divide the issued and outstanding Common Shares on a two-for-one basis. The subdivision of the Common Shares occurred on May 21, 2004. On January 20, 2005, 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, 2005 and ending January 23, 2006, to purchase for cancellation up to 13,409,006 common shares of the Company, being 5 per cent of the 268,180,123 common shares of the Company outstanding on January 12, 2005. As of the date of this Annual Information Form, no shares have been purchased. On March 9, 2005, the Board of Directors passed a resolution proposing an amendment to the Articles of the Company to sub-divide 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 5, 2005. 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. Dividends have been paid on the first day of January, April, July and October of each year since 2001. The following table restated for the two-for-one subdivision of the common shares which occurred in May 2004 shows the aggregate amount of the cash dividends declared per common share of the Company and accrued in each of its last three years ended December 31. 2004 2003 2002 ----- ----- ----- Cash dividends declared per common share $0.40 $0.30 $0.25 TRANSFER AGENTS AND REGISTRAR The Company's transfer agent and registrar for its common shares is Computershare Trust Company of Canada in the cities of Calgary and Toronto and Computershare Shareholder Services, Inc. in the city of New York. The registers for transfers of the Company's common shares are maintained by Computershare Trust Company of Canada. 47 DIRECTORS AND EXECUTIVE 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:
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS - ---- ----------------------- ---------------------------------------- Catherine M. Best Director(2)(4) Executive Vice-President, Risk Management and Chief Calgary, Alberta (age 51) Financial Officer of the Calgary Health Region from 2002 Canada 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/Banff, Alberta Director(3)(5) management and consulting company). Has served Canada (age 45) 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 55) since May 2001; prior thereto United States Ambassador to USA 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. John G. Langille President and Director Officer of the Company. Has served continuously as a Calgary, Alberta (age 59) director of the Company since June 1982. Canada Keith A.J. MacPhail Director(3)(4)(5) Chairman, President and Chief Executive Officer, Bonavista Calgary, Alberta (age 48) Petroleum Ltd. (independent oil and natural gas company) Canada 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 Chairman of the Company. Has served continuously as a Calgary, Alberta Director(3)(5) director of the Company since January 1989. Canada (age 59) James S. Palmer, C.M., A. O. Director(3)(4)(5) Chairman, Burnet, Duckworth & Palmer LLP (law firm). Has E., Q.C. (age 76) served continuously as a director of the Company since May Calgary, Alberta 1997. Currently serving on the board of directors of Canada Magellan Aerospace Corporation; Trenton Iron Works; Rally Energy Corp.; and, on the board of trustees for Rogers Sugar Income Fund. Dr. Eldon R. Smith, M.D. Director(1)(4)(5) Emeritus Professor and Former Dean, Faculty of Medicine, Calgary, Alberta (age 65) University of Calgary. Has served continuously as a Canada director of the Company since May 1997. Currently serving on the board of directors of Vasogen Inc.; and, Pheromone Sciences Corp.
48
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS - ---- ----------------------- ---------------------------------------- David A. Tuer Director(1)(2)(3) An independent businessman. Chairman, Calgary Health Calgary, Alberta (age 55) Region since October 2001 and President and CEO of Hawker Canada Resources Inc. (independent oil and natural gas company) from January 2003 to March 2005. 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 Rockwater Capital Corporation; and, Argo Energy Ltd. Steve W. Laut Chief Operating Officer Officer of the Company. Calgary, Alberta (age 47) Canada Real M. Cusson Senior Vice-President, Officer of the Company. Calgary, Alberta Marketing Canada (age 54) 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. Canada (age 52) Allen M. Knight Senior Vice-President, Officer of the Company. Calgary, Alberta International & Canada Corporate Development (age 55) Tim S. McKay Senior Vice-President, Officer of the Company. Calgary, Alberta Operations Canada (age 43) 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 Canada (age 54) Ltd. to 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 Canada (age 50) Jeffrey W. Wilson Senior Vice-President, Officer of the Company since September 2003; prior thereto Calgary, Alberta Exploration Exploration Manager of the Company. Canada (age 52) Mary-Jo Case Vice-President, Land Officer of the Company since May 2002; prior thereto Calgary, Alberta (age 46) Co-ordinator Land at PanCanadian Petroleum Limited to 1999 Canada 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. Canada and Environmental Affairs (age 42) Gordon M. Coveney Vice-President, Officer of the Company since September 2003; prior thereto Calgary, Alberta Exploration, Northeast Exploration Manager for the Company. Canada District (age 51) Randall S. Davis Vice-President, Officer of the Company since July 2004; prior thereto Calgary, Alberta Financial Accounting Manager, Financial Reporting of the Company to July 2002 Canada and Controls (age 38) and most recently Financial Controller of the Company from July 2002 to July 2004.
49
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS - ---- ----------------------- ---------------------------------------- Jerome W. Harvey Vice-President, Officer of the Company since April 2004; prior thereto Calgary, Alberta Commercial Operations Manager, Commercial Operations. Canada (age 51) Peter Janson Vice-President, Officer of the Company since December 2004; prior thereto Calgary, Alberta Engineering Integration Director, Production Planning and Control to June 2000 and Canada (age 47) Director, Health and Safety and Environment from June 2000 to November 2002 at Suncor Oil Sands and most recently Director, Engineering Integration of the Company from November 2002 to December 2004. Terry J. Jocksch Vice-President, Officer of the Company since April 2004; prior thereto Calgary, Alberta Exploitation East Exploitation Manager of the Company to April 2004. Canada (age 37) Christopher M. Kean Vice-President, Officer of the Company since December 2004; prior thereto Calgary, Alberta Utilities and Offsite, Manager Facilities Engineering to January 2002, Utilities Canada Horizon Oil Sands and Offsites Project Manager January 2002 to July 2002, Project Director, Utilities and Offsites July 2002 to July 2003 (age 41) and most recently General Manager, Utilities and Offsites July 2003 to December 2004. Philip A. Keele Vice-President, Mining, Officer of the Company since December 2004; prior thereto Calgary, Alberta Horizon Oil Sands from Mine Manager at Fording Coal Limited to February Canada Project 2001, Chief Mine Engineer of the Company February 2001 to (age 45) September 2002 and most recently Director, Mine Engineering of the Company from September 2002 to December 2004. Cameron S. Kramer Vice-President, Officer of the Company since September 2002; prior thereto Calgary, Alberta Field Operations Production Engineer of the Company to March 2000 and most Canada (age 37) recently Manager, Field Operations of the Company from April 2000 to September 2002. Leon Miura Vice-President, Officer of the Company since August 2003; prior thereto Calgary, Alberta Upgrading held progressively senior positions at Petroleos de Canada (age 50) 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. John S. J. Parr Vice-President, Officer of the Company since April 2004; prior thereto Calgary, Alberta Production, East Production Engineer, NE Gas of the Company to July 2001, Canada (age 43) Manager, Production Engineering of the Company from July 2002 to June 2002 and most recently Production Manager, Heavy Oil of the Company from July 2002 to April 2004. David A. Payne Vice-President, Officer of the Company since October 2004; prior thereto Calgary, Alberta Exploitation, West Exploitation Manager, Thermal Heavy of the Company to Canada (age 43) July 2000, Director, Exploitation of CNR International (U.K.) Limited a wholly-owned subsidiary of the Company from July 2000 to August 2003 and most recently Exploitation Manager, Technical Projects of the Company from August 2003 to October 2004. William R. Peterson Vice-President, Officer of the Company since April 2004; prior thereto Calgary, Alberta Production, West Production Manager, West of the Company. Canada (age 38) John C. Puckering Vice President, Site Officer of the Company since April 2004; prior thereto Calgary, Alberta Development General Manager DCL Construction Inc. to November 2001, Canada (age 58) President of 960925 Alberta Ltd. from November 2001 to April 2002, Manager, Site Development of the Company May 2002 to December 2002 and most recently General Manager Site Development of the Company from January 2003 to April 2004.
50
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS - ---- ----------------------- ---------------------------------------- Sheldon L. Schroeder Vice-President, Project Officer of the Company since April 2004; prior thereto Calgary, Alberta Control engineer with 729248 Alberta Ltd. to June 2001, Project Canada (age 37) Control Manager of the Company from June 2001 to September 2002 and most recently Director, Project Control of the Company from September 2002 to April 2004. Kendall W. Stagg Vice-President, Officer of the Company since October 2004; prior thereto Calgary, Alberta Exploration, West Cardium Geophysicist of the Company to April 2001, Chief Canada (age 43) Geophysicist of the Company from April 2001 to June 2002 and most recently Manager Exploration, B. C. of the Company from June 2002 to September 2004. Lynn M. Zeidler Vice-President, Bitumen Officer of the Company since August 2003; prior thereto Calgary, Alberta Production held progressively senior positions at Shell Canada Canada (age 48) Limited including on secondment from Shell Canada Limited as Manager-Tier 1 Implementation at Sable Offshore Energy Inc to September 2000 and most recently General Project Manager, Athabasca 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. Kimberly I. McKay Treasurer Officer of the Company since December 2004; prior thereto Calgary, Alberta (age 36) Financial Accountant of the Company to October 2001, Canada Advisor Capital Markets and Treasury Administration of the Company from October 2001 to July 2002 and most recently Treasury Manager of the Company from July 2002 to December 2004. Bruce E. McGrath Corporate Secretary Officer of the Company. Calgary, Alberta (age 55) Canada
(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. All of the current directors were elected to the Board at the last annual meeting of shareholders held on May 6, 2004. All of the current directors are standing for election at the Annual General Meeting of Shareholders scheduled for May 5, 2005. As at December 31, 2004, 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 4 per cent of the total outstanding common shares (approximately 5 per cent after the exercise of options held by them pursuant to the Company's stock option plan). Conflicts of Interest 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 51 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). AUDIT COMMITTEE INFORMATION Audit Committee Members The Audit Committee of the Board of Directors of the Company is comprised of Ms. C. M. Best, Chair, Messrs. G. D. Giffin and D. A. Tuer each of whom is (i) independent as defined under Canadian securities regulations NI 52-110 and the NYSE listing standards as they pertain to audit committees of listed issuers; and, (ii) financially literate. Ms. C. M. Best is a chartered accountant with 20 years experience as a staff member and partner of an international public accounting firm. During her tenure she was responsible for direct oversight and supervision of a large staff of auditors conducting audits of the financial reporting of significant publicly traded entities, many of which were oil and gas companies. This oversight and supervision required Ms. C. M. Best to maintain a current understanding of generally accepted accounting principles, and be able to assess their application in each of her clients. It also required an understanding of internal controls and financial reporting processes and procedures. Ambassador G. D. Giffin's education and experience relevant to the performance of his responsibilities as an audit committee member is derived from a thirty year law practice involving complex accounting and audit-related issues associated with complicated commercial transactions and disputes. He has developed extensive practical experience and an understanding of internal controls and procedures for financial reporting from his service on audit committees for several publicly traded issuers and continues pursuit of extensive professional reading and study on related subjects. Mr. D. A. Tuer's education and experience relevant to the performance of his responsibilities as an audit committee member is derived from professional training and a business career as a Chief Executive Officer in a large publicly traded company which provided experience in analyzing and evaluating financial statements and supervising persons engaged in the preparation, analysis and evaluation of financial statements of publicly traded companies. He has gained an understanding of internal controls and procedures for financial reporting through oversight of those functions, and the understanding of Audit Committee functions through his years of Chief Executive involvement. Auditor Service Fees Auditor Service 2004 2003 - --------------- ---------- -------- Audit fees $1,100,548 $886,000 Audit related fees $ 183,663 $ 12,500 Tax related fees $ 39,330 $ 11,000 All other fees $ 0 $ 10,000 52 LEGAL PROCEEDINGS From time to time, CNRL is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation may be material or may be indeterminate and the outcome of such litigation may materially impact the Company's financial condition or results of operations. While the Company assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. The claims that have been made to date are not currently expected to have a material impact on the Company's financial position. INTERESTS OF EXPERTS Canadian Natural's auditor is PricewaterhouseCoopers LLP, Chartered Accountants, 3100, 111-5th Avenue S. W. Calgary, Alberta T2P 5L3. The Company's audited consolidated financial statements for the year ended December 31, 2004 have been filed under National Instrument 51-102 in reliance on the report of PricewaterhouseCoopers LLP, independent chartered accountants, given on their authority as experts in auditing and accounting. Sproule Associates Limited, Ryder Scott Company and Gilbert Laustsen Jung Associates Ltd. have provided the Report on Reserves Data attached as Schedule "A" to this Annual Information Form in their capacity as the Company's Independent Qualified Reserves Evaluators. Sproule Associates Limited, Ryder Scott Company and Gilbert Laustsen Jung Associates Ltd. and their directors, officers and associates, collectively own less than 1% of the Company's outstanding common shares. ADDITIONAL INFORMATION Additional information relating to the Company can be found on the SEDAR website at www.sedar.com Additional information including Directors' and Executive Officers' remuneration and indebtedness, 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 17, 2005 in connection with the Annual and Special Meeting of Shareholders of Canadian Natural to be held on May 5, 2005 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, 2004 found on pages 39 to 67, 68 to 90 and 91 to 95 respectively, of the 2004 Annual Report to the Shareholders, which information is incorporated herein by reference. For additional copies of this Annual Information Form, please contact: Corporate Secretary of the Corporation at: 2500, 855 - 2nd Street S.W. Calgary, Alberta T2P 4J8 53 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. Except as noted in 1(c) (i), we have evaluated the Corporation's reserves data as at December 31, 2004. The reserves data consist of the following: (a) (i) proved oil and natural gas reserve quantities estimated as at December 31, 2004 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, 2004 using forecast prices and costs; and (ii) the related estimated future net revenue (c) (i) proved and proved plus probable bitumen and synthetic crude oil reserves relating to surface mineable oil sands projects estimated as at February 9, 2005 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. 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 natural 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, 2004 except as noted in 1(c)(i), and identifies the respective portions 54 thereof that we have evaluated and reported on to the Corporation's management and board of directors:
- ---------------------------------------------------------------------------------------------------- Independent Description and Location of Net Present Values of Future Cash Flows Qualified Preparation Reserves (Country (Before Income Taxes, 10% Discount Rate) Reserves Date of or Foreign -------------------------------------------- Evaluator or Evaluation Geographic Audited Evaluated Reviewed Total Auditor Report Area) MM$ MM$ MM$ MM$ - ---------------------------------------------------------------------------------------------------- Sproule Sproule Canada, USA $0 $11,242.36 $0 $11,242.36 Associates Ltd. Evaluated the P&NG Reserves as reported February 18, 2005. - ---------------------------------------------------------------------------------------------------- Ryder Scott Ryder Scott Canada (assets $0 $ 468.00 $0 $ 468.00 Company Evaluated the acquired November P&NG Reserves 2004) as reported February 18, 2005. - ---------------------------------------------------------------------------------------------------- Ryder Scott Ryder Scott United Kingdom $0 $ 6,427.80 $0 $ 6,427.80 Company Evaluated the and Offshore West P&NG Reserves Africa as reported February 18, 2005. - ---------------------------------------------------------------------------------------------------- Totals $0 $18,138.16 $0 $18,138.16 - ----------------------------------------------------------------------------------------------------
In addition all proved and proved plus probable company gross reserves have been evaluated for oil sands mining properties located in Canada. Horizon mining reserves are not part of Canadian Natural's year end. The Horizon reserves were evaluated as at February 9th, 2005. Gilbert Laustsen Jung Associates Ltd ("GLJ"), an independent qualified reserves evaluator, was retained by the Reserves Committee of Canadian Natural's Board of Directors to evaluate reserves associated with the Horizon Project incorporating both the mining and upgrading projects. These reserves were evaluated under SEC Industry Guide 7 and are discussed separately from the Company's conventional oil and gas activities. 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. 55 7. We have no responsibility to update our evaluation for events and circumstances occurring after their respective preparation dates. 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, 2005 SPROULE ASSOCIATES LIMITED Original Signed By: /s/ Harry J. Helwerda ------------------------------------ Harry J. Helwerda, P.Eng., Vice-President, Engineering, 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, Canada and U.S. RYDER SCOTT COMPANY Original Signed By: /s/ Jane Tink ------------------------------------ Jane Tink, P.Eng., Vice-President, Engineering GILBERT LAUSTSEN JUNG ASSOCIATES LTD. Original Signed By: /s/ James H. Willmon ------------------------------------ James H. Willmon, P.Eng. Vice-President 56 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 and surface mineable oil sands 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, 2004 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, 2004 using forecast prices and costs; (ii) the related estimated future net revenue; and, (c) (i) proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at February 9, 2005. Sproule Associates Limited, Ryder Scott Company and Gilbert Laustsen Jung Associates Ltd. all independent qualified reserves evaluators have 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 each of the independent qualified reserves evaluators to determine whether any restrictions placed by management affected the ability of the independent qualified reserves evaluators to report without reservation; and (c) reviewed the reserves data with management and the independent qualified reserves evaluators. 57 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 and surface mineable oil sands information; (b) the filing of the reports of the independent qualified reserves evaluators 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" Steve W. Laut Chief Operating Officer "Signed" Douglas A. Proll Senior Vice President, Finance "Signed" David A. Tuer Independent Director and Chair of the Reserve Committee "Signed" Keith A.J. MacPhail Independent Director and Member of the Reserve Committee Dated this 18th day of February, 2005 Calgary, Alberta EX-99 3 ex-2form40f_2004.txt EXHIBIT 2 EXHIBIT 2 --------- 2004 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets
AS AT DECEMBER 31 2004 2003 (millions of Canadian dollars) - ------------------------------------------------------------------------------------------------------------------------------ ASSETS CURRENT ASSETS Cash $ 28 $ 104 Accounts receivable and other 1,176 751 Current portion of other long-term assets (note 4) 34 - ------------ -------- 1,238 855 PROPERTY, PLANT AND EQUIPMENT (note 5) 17,064 13,714 OTHER LONG-TERM ASSETS (note 4) 108 74 ------------ -------- $ 18,410 $ 14,643 ============ ======== LIABILITIES CURRENT LIABILITIES Accounts payable $ 379 $ 464 Accrued liabilities 1,057 582 Current portion of long-term debt (note 6) 194 184 Current portion of other long-term liabilities (note 7) 260 130 ------------ -------- 1,890 1,360 LONG-TERM DEBT (note 6) 3,538 2,748 OTHER LONG-TERM LIABILITIES (note 7) 1,208 938 FUTURE INCOME TAX (note 8) 4,450 3,591 ------------ -------- 11,086 8,637 SHAREHOLDERS' EQUITY SHARE CAPITAL (note 9) 2,408 2,353 RETAINED EARNINGS 4,922 3,650 FOREIGN CURRENCY TRANSLATION ADJUSTMENT (note 10) (6) 3 ------------ -------- 7,324 6,006 ------------ -------- $ 18,410 $ 14,643 ============ ========
COMMITMENTS (note 13) Approved by the Board: (/S/ CATHERINE M. BEST) CATHERINE M. BEST Chair of the Audit Committee and Director (/S/ N. MURRAY EDWARDS) N. MURRAY EDWARDS Vice-Chairman of the Board and Director 69 CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT Consolidated Statements of Earnings
FOR THE YEARS ENDED DECEMBER 31 2004 2003 2002 (millions of Canadian dollars, except per common share amounts) - -------------------------------------------------------------------------------------------------------------------------------- REVENUE $ 7,547 $ 6,155 $ 4,459 Less: royalties (1,011) (872) (600) REVENUE, NET OF ROYALTIES 6,536 5,283 3,859 EXPENSES Production 1,400 1,209 931 Transportation 250 262 262 Depletion, depreciation and amortization 1,769 1,509 1,298 Asset retirement obligation accretion (note 7) 51 62 68 Administration 115 87 61 Stock-based compensation (note 7) 259 200 - Interest 189 201 203 Risk management activities 434 148 83 Foreign exchange gain (91) (335) (32) ----------- --------- ---------- 4,376 3,343 2,874 ----------- --------- ---------- EARNINGS BEFORE TAXES 2,160 1,940 985 Taxes other than income tax (note 8) 165 107 63 Current income tax (note 8) 116 92 8 Future income tax (note 8) 474 338 375 ----------- --------- ---------- NET EARNINGS $ 1,405 $ 1,403 $ 539 =========== ========= ========== NET EARNINGS PER COMMON SHARE (note 11) Basic $ 5.24 $ 5.23 $ 2.11 Diluted $ 5.20 $ 5.06 $ 2.04 =========== ========= ==========
Consolidated Statements of Retained Earnings
FOR THE YEARS ENDED DECEMBER 31 2004 2003 2002 (millions of Canadian dollars) - -------------------------------------------------------------------------------------------------------------------------------- BALANCE - BEGINNING OF YEAR AS PREVIOUSLY REPORTED $ 3,644 $ 2,414 $ 1,908 Change in accounting policy (note 2) 6 10 41 ----------- --------- ---------- BALANCE - BEGINNING OF YEAR AS RESTATED 3,650 2,424 1,949 Net earnings 1,405 1,403 539 Dividend on common shares (note 9) (107) (81) (64) Purchase of common shares (note 9) (26) (96) - ----------- --------- ---------- BALANCE - END OF YEAR $ 4,922 $ 3,650 $ 2,424 =========== ========= ==========
70 2004 ANNUAL REPORT CONSOLIDATED FINANCIAL STATEMENTS Consolidated Statements of Cash Flows
FOR THE YEARS ENDED DECEMBER 31 2004 2003 2002 (millions of Canadian dollars) - -------------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net earnings $ 1,405 $ 1,403 $ 539 Non-cash items Depletion, depreciation and amortization 1,769 1,509 1,298 Asset retirement obligation accretion 51 62 68 Stock-based compensation 249 200 - Unrealized risk management activities (40) - - Unrealized foreign exchange gain (94) (343) (36) Deferred petroleum revenue tax (recovery) (45) (9) 10 Future income tax 474 338 375 Deferred charges (33) 10 (84) Abandonment expenditures (32) (40) (43) Net change in non-cash working capital (note 14) (14) (48) (157) ----------- ---------- -------- 3,690 3,082 1,970 ----------- ---------- -------- FINANCING ACTIVITIES Issue (repayment) of bank credit facilities 357 (647) (1,234) Repayment of medium-term notes (125) - - Repayment of senior unsecured notes (54) (85) (16) Issue of US dollar debt securities 830 - 1,749 Repayment of obligations under capital leases (7) (8) (4) Dividend on common shares (101) (77) (60) Issue of common shares on exercise of stock options 24 89 84 Purchase of common shares (33) (144) - Net change in non-cash working capital (note 14) 6 (11) 27 ----------- ---------- -------- 897 (883) 546 ----------- ---------- -------- INVESTING ACTIVITIES Expenditures on property, plant and equipment (4,582) (2,486) (2,552) Net proceeds on sale of property, plant and equipment 7 20 76 ----------- ---------- -------- Net expenditures on property, plant and equipment (4,575) (2,466) (2,476) Net change in non-cash working capital (note 14) (88) 341 (25) ----------- ---------- -------- (4,663) (2,125) (2,501) ----------- ---------- -------- (DECREASE) INCREASE IN CASH (76) 74 15 CASH - BEGINNING OF YEAR 104 30 15 ----------- ---------- -------- CASH - END OF YEAR $ 28 $ 104 $ 30 =========== ========== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (note 14) 71 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 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 17. 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 of the consolidated financial statements. Such estimates primarily relate to unsettled transactions and events as of the date of 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 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 calculation of asset retirement obligations includes estimates of the future costs to settle the asset retirement obligation, the timing of the cash flows to settle the obligation, and the future inflation rates. The impact of differences between actual and estimated costs, timing and inflation 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. For mining activities the property acquisition, exploration and development costs 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 and major development projects. 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 for major development projects 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. 72 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT The Company reviews the carrying amount of its oil and natural gas properties ("the properties") relative to their recoverable amount ("the ceiling test") for each cost centre at each annual balance sheet date, or earlier if circumstances or events indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash flow from the properties using proved reserves and expected future prices and costs. If the carrying amount of the properties exceeds their recoverable amount, then an impairment loss equal to the amount by which the carrying amount of the properties exceeds their fair value is recognized in depletion. Fair value is calculated as the cash flow from those properties using proved and probable reserves and expected future prices and costs, discounted at a risk-free interest rate. Midstream assets are depreciated on a straight-line basis over their estimated lives. The Company reviews the recoverability of the carrying amount of the midstream assets at each annual balance sheet date. If the carrying amount of the midstream assets exceeds their recoverable amount, then an impairment loss equal to the amount by which the carrying amount of the midstream assets exceeds their fair value is recognized in depreciation. 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. ASSET RETIREMENT OBLIGATION The fair values of asset retirement obligations related to long-term assets are recognized as a liability in the period in which they are incurred. Retirement costs equal to the fair value of the asset retirement obligations are capitalized as part of the cost of the associated capital assets and are amortized to expense through depletion over the life of the asset. The fair value of the asset retirement obligation is estimated by discounting the expected future cash flows to settle the asset retirement obligation at the Company's credit-adjusted risk-free interest rate. In subsequent periods, the asset retirement obligation is adjusted for the passage of time and for any changes in the amount or timing of the underlying future cash flows. 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 exchange rate 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 10) 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. 73 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT REVENUE RECOGNITION Revenues are recognized when products have been delivered or services have been performed. STOCK-BASED COMPENSATION PLANS The Company accounts for its stock-based compensation plans using the fair 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 are 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. The Company also has a stock bonus plan. Contributions to the stock bonus plan are recorded as compensation expense over the vesting period. RISK MANAGEMENT ACTIVITIES Financial instruments that do not qualify as hedges under Accounting Guideline 13 or are not designated as hedges are recorded at fair value on the Company's consolidated balance sheet, with subsequent changes in fair value recognized in net earnings. The Company utilizes various financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are not used for trading purposes. The Company enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to protect cash flow for capital expenditure programs. The Company also enters into foreign currency denominated financial instruments to manage future US dollar denominated crude oil and natural gas sales. Gains or losses on these contracts are included in risk management activities. 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 contracts require the periodic exchange of payments without the exchange of the notional principle amount on which the payments are based. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. Gains or losses on interest rate contracts not designated as hedges are included in risk management activities. The Company enters into cross currency swap agreements to manage its currency exposure on long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense. Gains or 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 amortized into 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 are used to purchase common shares at the average market price during the year. The dilutive effect of convertible securities is calculated by applying the "as-if-converted" method, which assumes that the securities are converted at the beginning of the period and that income items are adjusted to net earnings. COMPARATIVE FIGURES Certain figures provided for prior years have been reclassified to conform to the presentation adopted in 2004. Common share data has been restated to reflect the two-for-one share split in May 2004. 74 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 2. CHANGES IN ACCOUNTING POLICIES ASSET RETIREMENT OBLIGATION Effective January 1, 2004, the Company retroactively adopted the CICA's Section 3110, "Asset Retirement Obligations". The Section requires the recognition of a liability for the fair value of the asset retirement obligation related to long-term assets. Retirement costs equal to the fair value of the asset 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 asset retirement obligation is adjusted for the passage of time and any changes in the amount or timing of the underlying future cash flows. Previously, future site restoration costs were accrued over the life of the Company's proved reserves. This new standard was adopted retroactively and prior period comparative balances have been restated. Adoption of the standard had the following effects on the Company's consolidated balance sheet as at December 31, 2003:
December 31, 2003 - -------------------------------------------------------------------------------------------------------------------------------- Increase property, plant and equipment $ 445 Decrease future site restoration liability $ (447) Increase asset retirement obligation $ 897 Increase future income tax liability $ 3 Decrease foreign currency translation adjustment $ (14) Increase retained earnings $ 6 ===========
Adoption of the standard had the following effects on the Company's consolidated statements of earnings and retained earnings:
Year Ended December 31 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Increase opening retained earnings $ 6 $ 10 $ 41 Decrease depletion, depreciation and amortization $ (120) $ (56) $ (16) Increase asset retirement obligation accretion $ 51 $ 62 $ 68 Increase (decrease) future income tax expense $ 28 $ (2) $ (21) ======= ========== =======
RISK MANAGEMENT ACTIVITIES Effective January 1, 2004, the Company prospectively adopted the CICA's Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments". Guideline 13 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. EIC 128 requires that financial instruments that are not designated as hedges be recorded at fair value on the Company's consolidated balance sheet, with subsequent changes in fair value recorded in earnings. The Company has designated certain of its derivative financial instruments (note 12) as hedges, including certain crude oil collars, natural gas collars, the currency swap on the US$125 million senior unsecured note, and certain interest rate swaps. Adoption of Guideline 13 and EIC 128 had the following effects on the Company's consolidated balance sheet as at January 1, 2004:
JANUARY 1, 2004 - -------------------------------------------------------------------------------------------------------------------------------- Increase financial instruments asset $ 40 Increase deferred revenue $ 40 ===========
The deferred revenue will be amortized to earnings over the term of the underlying contracts. PREFERRED SECURITIES Effective December 31, 2004, the Company early adopted changes to the CICA's Section 3860 "Financial Instruments - Presentation and Disclosure" that relate to contractual obligations that may be settled by delivery of the Company's common shares. Under the new rules, these obligations must be classified as liabilities on the Company's consolidated balance sheets. Previously, these obligations were classified as equity. These changes have been adopted retroactively and prior periods have been restated. Adoption of the changes had the following effects on the Company's consolidated financial statements:
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Increase long-term debt $ 96 $ 103 $ 126 Decrease preferred securities $ (96) $ (103) $ (126) Increase interest expense $ 9 $ 9 $ 10 Increase foreign exchange gain $ 7 $ 23 $ 1 (Decrease) increase future income tax expense $ (1) $ 1 $ (4) Decrease dividend on preferred securities, net of tax $ (5) $ (5) $ (6) Decrease revaluation of preferred securities, net of tax $ (4) $ (18) $ (1) ======== ======= ============
75 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT FULL COST ACCOUNTING Effective January 1, 2004, the Company prospectively adopted the CICA's 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 their recoverable amount, calculated as 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 fair value of the assets, calculated as the present value of expected cash flows using proved and probable reserves and expected future prices and costs. The adoption of this standard had no effect on the Company's consolidated financial statements for the year ended December 31, 2004. 3. BUSINESS COMBINATIONS PETROVERA PARTNERSHIP In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as the Petrovera Partnership ("Petrovera"), for $471 million. The acquisition was accounted for based on the purchase method. Results from Petrovera are consolidated with the results of the Company effective from 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:
FEBRUARY 1, 2004 - -------------------------------------------------------------------------------------------------------------------------------- Purchase price: Cash consideration $ 467 Cash acquired (23) Non-cash working capital deficit assumed 27 ------- Total purchase price $ 471 ======= Purchase price allocated as follows: Property, plant and equipment $ 643 Future income tax liability (129) Asset retirement obligation (43) ------- $ 471 =======
RIO ALTO EXPLORATION LTD. In July 2002, the Company paid cash of $850 million and issued 20,016,436 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 from Rio Alto are consolidated with the results of the Company effective from 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 ========
76 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 4. OTHER LONG-TERM ASSETS
2004 2003 - -------------------------------------------------------------------------------------------------------------------------------- Risk management (note 12) $ 66 $ - Deferred charges 76 74 ----------- ------- 142 74 Less: current portion 34 - ----------- ------- $ 108 $ 74 =========== =======
5. PROPERTY, PLANT AND EQUIPMENT
2004 2003 ------------------------------------------ -------------------------------------------- ACCUMULATED Accumulated DEPLETION AND depletion and COST DEPRECIATION NET Cost depreciation Net - -------------------------------------------------------------------------------------------------------------------------------- Oil and natural gas North America $ 19,750 $ 6,356 $ 13,394 $ 15,914 $ 4,924 $ 10,990 North Sea 2,562 739 1,823 1,971 534 1,437 Offshore West Africa 1,101 192 909 806 139 557 Horizon Project 672 - 672 381 - 381 Midstream 241 32 209 225 25 200 Head office 101 44 57 70 31 39 ------------ ------------ ------------ --------- --------- --------- $ 24,427 $ 7,363 $ 17,064 $ 19,367 $ 5,653 $ 13,714 ============ ============ ============ ========= ========= =========
During the year ended December 31, 2004, the Company capitalized administrative overhead of $19 million (2003 - $12 million, 2002 - $13 million) relating to exploration and development in the North Sea and Offshore West Africa and $35 million (2003 - $23 million, 2002 - $4 million) relating mainly to the Horizon Project in North America. Included in property, plant and equipment are unproved land and major development projects that are not subject to depletion or depreciation:
2004 2003 - ------------------------------------------------------------------------------------------------------------------------------ Oil and natural gas North America $ 1,028 $ 789 North Sea 44 56 Offshore West Africa 536 251 Horizon Project 672 381 ----------- --------- $ 2,280 $ 1,477 =========== =========
6. LONG-TERM DEBT
2004 2003 - ------------------------------------------------------------------------------------------------------------------------------ Bank credit facilities US dollar bankers' acceptances (2004 - US$471 million, 2003 - US$207 million) $ 557 $ 268 Medium-term notes 6.85% unsecured debentures due May 28, 2004 - 125 7.40% unsecured debentures due March 1, 2007 125 125 Senior unsecured notes 6.42% due May 27, 2004 (2004 - US$nil, 2003 - US$40 million) - 52 7.69% due December 19, 2005 (2004 - US$125 million, 2003 - US$125 million) 194 194 Adjustable rate due May 27, 2009 (2004 - US$93 million, 2003 - US$93 million) 112 120 Preferred securities 8.30% due June 25, 2011 (2004 - US$80 million, 2003 - US$80 million) 96 103 US dollar debt securities 6.70% due July 15, 2011 (2004 - US$400 million, 2003 - US$400 million) 482 517 5.45% due October 1, 2012 (2004-US$350 million , 2003 - US$350 million) 421 452 4.90% due December 1,2014 (2004 - US$350 million, 2003 - US$nil) 421 - 7.20% due January 15, 2032 (2004 - US$400 million, 2003 - US$400 million) 482 517 6.45% due June 30, 2033 (2004 - US$350 million, 2003 - US$350 million) 421 452 5.85% due February 1, 2035 (2004 - US$350 million, 2003 - US$nil) 421 - Obligations under capital leases - 7 ----------- --------- 3,732 2,932 Less: current portion of long-term debt 194 184 ----------- --------- $ 3,538 $ 2,748 =========== =========
77 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT BANK CREDIT FACILITIES The Company has unsecured syndicated bank credit facilities of $3,425 million, comprised of a $100 million operating demand facility, a revolving credit and term loan facility of $1,825 million and a revolving and term loan facility of $1,500 million. The $1,825 million revolving credit and term loan facility is fully revolving for 364-day periods with a term to June 2005 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 $1,500 million revolving credit facility has a five-year term, with three, one-year extension provisions. If the facility is not extended, the amount outstanding would be repayable in December 2009. The facilities provide that the borrowings may be made by way of operating advances, prime loans, bankers' acceptances, US base rate loans or US dollar LIBOR advances, which bear interest at the bank's prime rates or at money market rates plus applicable margins. The Company fixed the exchange rate on the repayment of its US dollar bankers' acceptances using foreign currency financial derivatives (note 12). The US dollar bankers' acceptances were repaid in January 2005 at a C$/US$ exchange rate of 1.180. The weighted average interest rate of the bank credit facilities outstanding at December 31, 2004, was 3.47% (2003 - 2.32%). In addition to the outstanding debt, letters of credit aggregating $24 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. In May 2004, the Company repaid the $125 million 6.85% unsecured debentures due May 2004, which were issued under a previous medium-term note program. The Company has $125 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 in September 2003. The 6.42% senior unsecured notes were repaid in May 2004. In May 2003, the Company prepaid the US$50 million 6.50% senior unsecured notes due May 2008. The adjustable rate senior unsecured notes bear interest at 6.54% and have annual principal repayments of US$31 million commencing in May 2007, through May 2009. These debt instruments contain covenants pertaining to the Company's net worth, certain financial ratios and the ability to grant security. Through a currency swap, the principle and interest repayments on the US$125 million, 7.69% notes due December 2005 have been fixed at $194 million and 7.30%, respectively (note 12). US DOLLAR DEBT SECURITIES In December 2004, the Company issued US$350 million of debt securities maturing December 2014, bearing interest at 4.90% and US$350 million of debt securities maturing February 2035, bearing interest at 5.85%. Proceeds from the securities issued were used to repay bankers' acceptances under the Company's bank credit facilities. The Company has entered into certain interest rate swap contracts to convert the fixed rate interest coupon into a floating interest rate on the securities due December 2014 (note 12). After issuing the above securities, the Company has US$1.3 billion remaining on a US$2.0 billion shelf prospectus filed in May 2003 that allows for the issue of debt securities in the United States until June 2005. If issued, these securities will bear interest as determined at the date of issuance. PREFERRED SECURITIES Annual principal repayments of approximately US$27 million are required commencing June 2009 through June 2011. The notes are subordinated to the other 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 interest, principal and principal prepayment amounts by delivering common shares to the Trustee of the subordinated notes. The semi-annual interest 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. REQUIRED DEBT REPAYMENTS Required debt repayments are as follows:
Year REPAYMENT - -------------------------------------------------------------------------------------------------------------------------------- 2005 $ 194 2006 $ - 2007 $ 162 2008 $ 37 2009 $ 69 Thereafter $ 2,713
No debt repayments are reflected for the bank credit facilities due to the extendable nature of the facilities. 78 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 7. OTHER LONG-TERM LIABILITIES
2004 2003 - -------------------------------------------------------------------------------------------------------------------------------- Asset retirement obligation $ 1,119 $ 897 Stock-based compensation 323 171 Deferred revenue (note 12) 26 - 1,468 1,068 Less: current portion 260 130 ------------ ---------- $ 1,208 $ 938 ============ ==========
ASSET RETIREMENT OBLIGATION At December 31, 2004, the Company's total estimated undiscounted costs to settle its asset retirement obligations with respect to crude oil and natural gas properties and facilities was $3,063 million (2003 - $2,281 million). These costs will be incurred over several years and have been discounted using a credit-adjusted risk-free interest rate of 6.7%. A reconciliation of the discounted asset retirement obligation is as follows:
2004 2003 - -------------------------------------------------------------------------------------------------------------------------------- Asset retirement obligation Balance - beginning of year $ 897 $ 867 Liabilities incurred 339 117 Liabilities settled (32) (40) Asset retirement obligation accretion 51 62 Revision of estimates (86) (6) Foreign exchange (50) (103) ----------- --------- Balance - end of year $ 1,119 $ 897 =========== =========
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. STOCK-BASED COMPENSATION The Company's Stock Option Plan ("Option Plan") results 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 could be realized within the next 12 month period if all vested options are surrendered for cash settlement.
2004 2003 - -------------------------------------------------------------------------------------------------------------------------------- Stock-based compensation Balance - beginning of year $ 171 $ - Stock-based compensation provision 259 200 Expense relating to share bonus plan (10) - Cash payment for options surrendered (80) (31) Transferred to common shares (38) (8) Capitalized with respect to Horizon Project 21 10 Balance - end of year 323 171 Less: current portion of stock-based compensation 243 130 ----------- --------- $ 80 $ 41 =========== =========
79 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 8. TAXES TAXES OTHER THAN INCOME TAX
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Current petroleum revenue tax $ 190 $ 106 $ 41 Deferred petroleum revenue tax (45) (9) 10 Provincial capital taxes and surcharges 20 10 11 Other - - 1 ----------- --------- -------- $ 165 $ 107 $ 63 =========== ========= ========
INCOME TAX The provision for income tax is as follows:
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Current income tax expense Current income tax - North America $ 89 $ 43 $ - Large Corporations Tax - North America 11 16 21 Current income tax - North Sea 2 23 (19) Current income tax - Offshore West Africa 13 10 6 Current income tax - other 1 - - ----------- --------- -------- 116 92 8 Future income tax expense 474 338 375 ----------- --------- --------- Income tax $ 590 $ 430 $ 383 =========== ========= =========
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:
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Canadian statutory income tax rate 39.3% 41.1% 42.4% ========= ======== ========= Income tax provision at statutory rate $ 849 $ 797 $ 418 Effect on income taxes of: Non-deductible portion of Canadian crown payments 221 285 211 Canadian resource allowance (270) (281) (243) Large Corporations Tax 11 16 21 Deductible UK petroleum revenue tax (57) (40) (22) Foreign tax rate differentials (31) 20 (1) Federal income tax rate reductions - (247) - Provincial income tax rate reductions (66) (31) (21) UK income tax rate increase - - 34 Non-taxable portion of foreign exchange (36) (103) (21) Other (31) 14 7 --------- -------- --------- Income tax $ 590 $ 430 $ 383 ========= ======== =========
The following table summarizes the temporary differences that give rise to the future income tax liability:
2004 2003 - ------------------------------------------------------------------------------------------------------------------------------ Future income tax liabilities Property, plant and equipment $ 3,760 $ 2,884 Timing of partnership items 1,254 1,095 Foreign exchange gain on long-term debt 102 90 Risk management 19 - Other 43 14 Future income tax assets Asset retirement obligation (418) (365) Capital loss carryforwards (92) - Attributed Canadian Royalty Income (54) (58) Stock-based compensation (106) (56) Deferred petroleum revenue tax (58) (13) ----------- ---------- Future income tax liability $ 4,450 $ 3,591 =========== ==========
80 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 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. Current income tax will vary and is dependent upon the amount of capital expenditures incurred in Canada and the way it is deployed. During 2004, the Government of Alberta passed legislation to reduce its corporate income tax rate by 1.0% effective April 1, 2004. Accordingly, the Company's future income tax liability was reduced by $66 million. 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. 9. 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
2004 2003 -------------------------- --------------------------- COMMON SHARES NUMBER OF Number of SHARES shares (thousands) AMOUNT (thousands) Amount - -------------------------------------------------------------------------------------------------------------------------------- Balance - beginning of year 267,463 $ 2,353 267,552 $ 2,304 Issued upon exercise of stock options 1,591 24 5,381 89 Previously recognized liability on stock options exercised for common shares - 38 - 8 Purchase of common shares under Normal Course Issuer Bid (873) (7) (5,470) (48) ------- ---------- ------- ---------- Balance - end of year 268,181 $ 2,408 267,463 $ 2,353 ======= ========== ======= ==========
SHARE SPLIT The Company's shareholders approved a subdivision or share split of its issued and outstanding common shares on a two-for-one basis at the Company's Annual and Special Meeting held on May 6, 2004. All common share and per common share amounts have been restated to retroactively reflect the share split. NORMAL COURSE ISSUER BID During 2004, the Company purchased 873,400 common shares at an average price of $38.01 per common share for a total cost of $33 million. The excess cost over book value of the common shares purchased was applied to reduce retained earnings. During 2003, the Company purchased 5,469,600 common shares at an average price of $26.26 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 2005, the Company renewed its Normal Course Issuer Bid, allowing the Company to purchase up to 13,409,006 common shares or 5% of the Company's outstanding common shares on the date of announcement, during the 12-month period beginning January 24, 2005 and ending January 23, 2006. As at February 18, 2005, 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 18, 2005, the Board of Directors set the Company's regular quarterly dividend at $0.1125 per common share (2004 - $0.10 per common share, 2003 - $0.075 per common share, 2002 - $0.0625 per common share) commencing with the April 1, 2005 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. 81 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 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. For the year ended December 31, 2004, the Company recorded compensation expense of $249 million (2003 - $200 million). As at December 31, 2004, the total liability for expected cash settlements under the Option Plan is $323 million (2003 - $171 million), of which $243 million (2003 - $130 million) is included as a current liability. During the year ended December 31, 2004, cash payments of $80 million were made for 3,781,000 stock options surrendered (2003 - cash payments of $31 million for 2,674,000 stock options surrendered). Prior to the modification, the Company disclosed pro-forma measures of net earnings and net earnings 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, 2004 and 2003:
2004 2003 -------------------------- --------------------------- STOCK WEIGHTED Stock Weighted OPTIONS AVERAGE options average (thousands) EXERCISE (thousands) exercise PRICE price - -------------------------------------------------------------------------------------------------------------------------------- Outstanding - beginning of year 17,789 $ 19.72 25,765 $ 18.57 Granted 4,861 $ 35.89 1,336 $ 26.16 Exercised for common shares (1,591) $ 15.10 (5,381) $ 16.57 Surrendered for cash settlement (3,781) $ 18.71 (2,674) $ 17.36 Forfeited (1,017) $ 27.72 (1,257) $ 21.39 ------ ------------ ------ --------- Outstanding - end of year 16,261 $ 24.74 17,789 $ 19.72 ------ ------------ ------ --------- Exercisable - end of year 3,816 $ 19.85 4,646 $ 17.33 ====== ============ ====== =========
The range of exercise prices of stock options outstanding and exercisable at December 31, 2004 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 - -------------------------------------------------------------------------------------------------------------------------------- $10.50 - $14.99 15 0.40 $ 13.16 15 $ 13.16 $15.00 - $19.99 7,175 2.10 $ 18.82 2,586 $ 18.41 $20.00-$24.99 3,830 3.05 $ 22.50 1,082 $ 22.39 $25.00-$29.99 862 4.71 $ 26.86 112 $ 26.82 $30.00-$34.99 2,978 5.12 $ 33.80 21 $ 33.93 $35.00-$39.99 645 5.17 $ 35.79 - $ - $40.00-$44.99 318 5.60 $ 40.99 - $ - $45.00-$48.99 438 5.90 $ 47.87 - $ - ------ ---- ---------- ----- ----------- 16,261 3.30 $ 24.74 3,816 $ 19.85 ====== ==== ========== ===== ===========
10. 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.
2004 2003 - -------------------------------------------------------------------------------------------------------------------------------- Balance - beginning of year as previously reported $ 17 $ 24 Change in accounting policy (note 2) (14) 2 ----------- ------- Balance - beginning of year as restated 3 26 Unrealized loss on translation of net investment (24) (124) Hedge of net investment with US dollar denominated debt, net of tax 15 101 Balance - end of year $ (6) $ 3 =========== =======
82 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 11. NET EARNINGS PER COMMON SHARE The following table provides a reconciliation between basic and diluted amounts per common share:
(thousands of shares) 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------------- Weighted average common shares outstanding - basic 268,112 268,470 255,766 Effect of dilutive stock options (1) - 2,444 5,488 Assumed settlement of preferred securities with common shares 2,230 3,908 5,362 -------- ------- ------- Weighted average common shares outstanding - diluted 270,342 274,822 266,616 -------- ------- ------- Net earnings $ 1,405 $ 1,403 $ 539 Interest on preferred securities, net of tax 5 5 6 Revaluation of preferred securities, net of tax (4) (18) (1) ------- ------- ------- Diluted net earnings $ 1,406 $ 1,390 $ 544 ------- ------- ------- Net earnings per common share Basic $ 5.24 $ 5.23 $ 2.11 Diluted $ 5.20 $ 5.06 $ 2.04 ======= ======= =======
(1) The modification of the Option Plan described in note 9 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, 639,832 stock options with a weighted average exercise price of $24.17, were excluded from the calculation as their effect on per common share amounts was not dilutive. 12. FINANCIAL INSTRUMENTS RISK MANAGEMENT On January 1, 2004, the fair values of all outstanding derivative financial instruments that were not designated as hedges for accounting purposes were recorded on the consolidated balance sheet, with an offsetting net deferred revenue amount (note 2). Subsequent changes in fair value are recognized on the consolidated balance sheet and in net earnings. The estimated fair value for all derivative financial instruments is based on third party indications. The following table reconciles the change in derivative financial instruments:
ASSET (LIABILITY) RISK MANAGEMENT DEFERRED TOTAL UNREALIZED MARK-TO-MARKET REVENUE GAIN/(LOSS) - ------------------------------------------------------------------------------------------------------------------------------- Balance - beginning of year $ 40 $(40) $ - Change in fair value of existing financial instruments at beginning of year and new financial instruments entered in 2004 468 - 468 Put premiums 32 - 32 Realized risk management activities (474) - (474) Amortization of deferred revenue - 14 14 ----- ---- ----- Balance - end of year 66 (26) $ 40 ===== Less: current portion 34 (17) ----- ---- $ 32 $ (9) ===== ====
FINANCIAL CONTRACTS The Company's financial instruments recognized in the consolidated balance sheets consist of cash, accounts receivable, accounts payable, accrued liabilities, risk management activities, stock-based compensation 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, stock-based compensation and long-term debt with variable interest rates approximate their fair value. 83 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT The estimated fair values of other financial instruments are as follows:
2004 2003 ------------------------------ ----------------------------- CARRYING VALUE FAIR VALUE Carrying value Fair Value - ---------------------------------------------------------------------------------------------------------------------------------- ASSET (LIABILITY) Derivative financial instruments $ 66 $ 33 $ - $ 16 Fixed rate notes $ (3,175) $ (3,364) $ (2,664) $ (2,880) ============ =========== =========== ===========
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, 2004:
REMAINING TERM VOLUME AVERAGE PRICE INDEX - -------------------------------------------------------------------------------------------------------------------------------- OIL Oil price collars Jan 2005 - Mar 2005 140,500 bbl/d US$36.09 - US$45.32 WTI Apr 2005 - Jun 2005 150,500 bbl/d US$39.98 - US$49.39 WTI Jul 2005 - Sep 2005 139,500 bbl/d US$41.60 - US$51.35 WTI Oct 2005 - Dec 2005 139,500 bbl/d US$41.60 - US$51.35 WTI Oil puts Jan 2005 - Mar 2005 99,000 bbl/d US$29.21 WTI Apr 2005 - Jun 2005 123,000 bbl/d US$29.89 WTI Jul 2005 - Sep 2005 50,000 bbl/d US$31.09 WTI Oct 2005 - Dec 2005 50,000 bbl/d US$29.81 WTI
REMAINING TERM VOLUME AVERAGE PRICE INDEX - -------------------------------------------------------------------------------------------------------------------------------- NATURAL GAS AECO collars Jan 2005 - Mar 2005 640,000 GJ/d C$6.24 - C$11.69 AECO Apr 2005 - Jun 2005 740,000 GJ/d C$5.83 - C$7.89 AECO Jul 2005 - Sep 2005 640,000 GJ/d C$5.88 - C$7.92 AECO Oct 2005 - Dec 2005 114,500 GJ/d C$6.00 - C$8.08 AECO
REMAINING TERM AMOUNT AVERAGE EXCHANGE RATE ($ millions) (US$/C$) - -------------------------------------------------------------------------------------------------------------------------------- FOREIGN CURRENCY Currency collars Jan 2005 - Aug 2005 US$10/month 1.37 - 1.49
REMAINING TERM AMOUNT EXCHANGE RATE INTEREST RATE INTEREST RATE ($ millions) (US$/C$) (US$) (C$) - -------------------------------------------------------------------------------------------------------------------------------- Currency swap Jan 2005 - Dec 2005 US$125 1.55 7.69% 7.30% Currency forward Jan 2005 - Jan 2005 US$471 1.18 n/a n/a
REMAINING TERM AMOUNT FIXED RATE FLOATING RATE ($ millions) - -------------------------------------------------------------------------------------------------------------------------------- INTEREST RATE Swaps - fixed to floating Jan 2005 - Jan 2005 US$200 7.20% LIBOR(1) + 3.00% Jan 2005 - Jul 2006 US$200 6.70% LIBOR(1) + 1.65% Jan 2005 - Jan 2007 US$200 7.20% LIBOR(1) + 2.23% Jan 2005 - Oct 2012 US$350 5.45% LIBOR(1) + 0.81% Jan 2005 - Dec 2014 US$350 4.90% LIBOR(1) + 0.38% Swaps - floating to fixed Jan 2005 - Mar 2007 C$10 7.36% CDOR(2)
(1) London Interbank Offered Rate (2) Canadian Deposit Overnight Rate 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 possible 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. 84 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 13. COMMITMENTS The Company has committed to certain payments as follows:
2005 2006 2007 2008 2009 Thereafter - -------------------------------------------------------------------------------------------------------------------------------- Natural gas transportation $ 194 $ 147 $ 100 $ 78 $ 37 $ 168 Oil transportation and pipeline $ 11 $ 9 $ 11 $ 12 $ 13 $ 154 Offshore equipment operating lease $ 110 $ 48 $ 48 $ 48 $ 48 $ 184 Baobab Project $ 99 $ - $ - $ - $ - $ - Offshore drilling and other $ 125 $ 8 $ - $ - $ - $ - Electricity $ 26 $ 28 $ 20 $ 13 $ 8 $ 34 Office lease $ 21 $ 21 $ 22 $ 23 $ 24 $ 30 Processing $ 5 $ 2 $ - $ - $ - $ - Horizon Project $ 99 $ - $ - $ - $ - $ -
14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Changes in non-cash working capital were as follows:
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Decrease (increase) in non-cash working capital Accounts receivable and other $ (329) $ 35 $ (164) Accounts payable 39 125 (145) Accrued liabilities 194 122 154 ----------- --------- ---------- Net change in non-cash working capital $ (96) $ 282 $ (155) ----------- --------- ---------- Relating to: Operating activities $ (14) $ (48) $ (157) Financing activities 6 (11) 27 Investing activities (88) 341 (25) ----------- --------- ---------- $ (96) $ 282 $ (155) =========== ========= ==========
Other cash flow information: 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------------ Interest paid $ 192 $ 178 $ 132 Taxes paid $ 218 $ 51 $ 160
15. SEGMENTED INFORMATION The Company's oil and natural gas activities are conducted in three geographic segments: North America, 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. Activities that are not included in the above segments are included in the segmented information as other. Inter segment eliminations include internal transportation and electricity charges. 85 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 15. Segmented information (continued)
Oil and Natural Gas --------------------------------------------------------------------------------------- North America North Sea Offshore West Africa --------------------------- --------------------------- --------------------------- 2004 2003 2002 2004 2003 2002 2004 2003 2002 ------- ------- ------- ------- ------- ------- ------- ------- ------- Revenue $ 5,979 $ 5,021 $ 3,719 $ 1,317 $ 953 $ 620 $ 222 $ 155 $ 102 Less: royalties (1,003) (868) (564) (2) 1 (33) (6) (5) (3) ------- ------- ------- ------- ------- ------- ------- ------- ------- Revenue, net of royalties 4,976 4,153 3,155 1,315 954 587 216 150 99 ------- ------- ------- ------- ------- ------- ------- ------- ------- Segmented expenses Production 976 845 656 370 314 229 36 38 35 Transportation 256 264 273 32 30 20 - - - Depletion, depreciation and 1,444 1,209 1,022 265 252 188 53 41 80 amortization Asset retirement obligation accretion 28 26 20 22 36 48 1 - - Realized risk management activities 362 157 76 112 (9) 7 - - - ------- ------- ------- ------- ------- ------- ------- ------- ------- Total segmented expenses 3,066 2,501 2,047 801 623 492 90 79 115 ------- ------- ------- ------- ------- ------- ------- ------- ------- Segmented earnings before the following $ 1,910 $ 1,652 $ 1,108 $ 514 $ 331 $ 95 $ 126 $ 71 $ (16) ======= ======= ======= ======= ======= ======= ======= ======= ======= Non-segmented expenses Administration Stock-based compensation Interest Unrealized risk management activities Foreign exchange gain Total non-segmented expenses Earnings before taxes Taxes other than income tax Current income tax expense Future income tax expense Net earnings
Capital expenditures
2004 ------------------------------------------------------------------------------ Cash Non-cash Capital Fair value Capitalized consideration consideration expenditure adjustments(1) costs ------------- ------------- ------------ -------------- ----------- Oil and natural gas North America $ 3,329 $ 26 $ 3,355 $ 482 $ 3,837 North Sea 608 - 608 172 780 Offshore West Africa 296 - 296 - 296 ------- ------- ------- ------- ------- 4,233 26 4,259 654 4,913 Horizon Project 291 - 291 - 291 Midstream 16 - 16 - 16 Head office 35 - 35 - 35 ------- ------- ------- ------- ------- $ 4,575 $ 26 $ 4,601 $ 654 $ 5,255 ======= ======= ======= ======= =======
- ------------ (1) Asset retirement obligations, future income tax adjustments on non tax base assets, and other fair value adjustments. 86 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT
Midstream Other Inter-segment Elimination Total - ----------------------------- ----------------------------- ----------------------------- ----------------------------- 2004 2003 2002 2004 2003 2002 2004 2003 2002 2004 2003 2002 - ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- $ 68 $ 61 $ 52 $ 1 $ - $ - $ (40) $ (35) $ (34) $ 7,547 $ 6,155 $ 4,459 - - - - - - - - - (1,011) (872) (600) - ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- 68 61 52 1 - - (40) (35) (34) 6,536 5,283 3,859 - ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- 20 15 14 - - - (2) (3) (3) 1,400 1,209 931 - - - - - - (38) (32) (31) 250 262 262 7 7 8 - - - - - - 1,769 1,509 1,298 - - - - - - - - - 51 62 68 - - - - - - - - - 474 148 83 - ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- 27 22 22 - - - (40) (35) (34) 3,944 3,190 2,642 - ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- ------- $ 41 $ 39 $ 30 $ 1 $ - $ - $ - $ - $ - 2,592 2,093 1,217 ======= ======= ======= ======= ======= ======= ======= ======= ======= ======= ======= ======= 115 87 61 259 200 - 189 201 203 (40) - - (91) (335) (32) ------- ------- ------- 432 153 232 ------- ------- ------- 2,160 1,940 985 165 107 63 116 92 8 474 338 375 ------- ------- ------- $ 1,405 $ 1,403 $ 539 ======= ======= =======
2003 ------------------------------------------------------------------------------ Cash Non-cash Capital Fair value Capitalized consideration consideration expenditures adjustments(1) costs ------------- ------------- ------------ -------------- ----------- Oil and natural gas North America $ 1,769 $ - $ 1,769 $ - $ 1,769 North Sea 338 - 338 25 353 Offshore West Africa 176 - 176 - 176 ------- ------- ------- ------- ------- 2,283 - 2,283 25 2,308 Horizon Project 152 - 152 - 152 Midstream 11 - 11 - 11 Head office 20 - 20 - 20 ------- ------- ------- ------- ------- $ 2,466 $ - $ 2,466 $ 25 $ 2,491 ======= ======= ======= ======= =======
87 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT
Segmented property, plant and equipment, net 2004 2003 - -------------------------------------------- -------- -------- Oil and natural gas North America $ 13,394 $ 10,990 North Sea 1,823 1,437 Offshore West Africa 909 667 Horizon Project 672 381 Midstream 209 200 Head office 57 39 -------- -------- $ 17,064 $ 13,714 ======== ========
Segmented assets 2004 2003 - ---------------- -------- -------- Oil and natural gas North America $ 14,455 $ 11,731 North Sea 2,036 1,562 Offshore West Africa 922 703 Horizon Project 672 381 Midstream 268 227 Head office 57 39 -------- -------- $ 18,410 $ 14,643 ======== ========
16. Subsequent event On February 9, 2005, the Company's Board of Directors unanimously authorized the Company to proceed with Phase 1 of the Horizon Oil Sands Project. The Horizon Project is designed as a phased development and includes two components: the mining of bitumen and an onsite upgrader. Phase 1 production is targeted to begin at 110,000 bbl/d of 34(degree) API light sweet, synthetic crude oil ("SCO"). Phase 2 would increase production to 155,000 bbl/d of SCO. Phase 3 would further increase production to 232,000 bbl/d of SCO. Total expected capital costs for all three phases of the development are estimated at $10.8 billion. Capital costs for the first phase of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million, with $1.4 billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2 billion to be incurred in 2006, 2007 and 2008, respectively. 17. 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 2004 2003 2002 - --------------------------------------------------------------- ----- ------- ------- ------- Net earnings - Canadian GAAP $ 1,405 $ 1,403 $ 539 Adjustments, net of tax Depletion (A) 4 4 (5) Derivative financial instruments (B) (9) (49) 29 Capitalized interest (C) 16 - - Asset retirement obligation accretion (D) - - 41 Cumulative effect of change in accounting policy (D) - (4) - Tax effect of flow-through shares (E) - - (1) ------- ------- ------- Net earnings - US GAAP $ 1,416 $ 1,354 603 ======= ======= ======= Net earnings - US GAAP per common share Basic $ 5.28 $ 5.04 $ 2.36 Diluted $ 5.24 $ 4.88 $ 2.28 ------- ------- -------
88 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT Comprehensive income under US GAAP would be as follows:
(millions of Canadian dollars) Notes 2004 2003 2002 - ------------------------------ ------ -------- -------- -------- Net earnings- US GAAP $ 1,416 $ 1,354 $ 603 Amortization of FAS 133 adjustment (B) 8 20 31 Foreign currency translation adjustment (F) (9) (23) (49) -------- -------- -------- Comprehensive income $ 1,415 $ 1,351 $ 585 ======== ======== ========
The application of US GAAP would have the following effects on the consolidated balance sheets as reported:
2004 --------------------------------------------- Canadian Increase (millions of Canadian dollars) Notes GAAP (Decrease) US GAAP - ------------------------------ ------ -------- ---------- -------- Property, plant and equipment (A) $ 17,064 $ (27) $ 17,037 Current portion of other long-term assets (B) $ 34 $ (33) $ 1 Current portion of long-term debt (B) $ 194 $ (44) $ 150 Future income tax (A,B,C) $ 4,450 $ 6 4,456 Shareholders' equity $ 7,324 $ (22) $ 7,302
2003 --------------------------------------------- Canadian Increase (millions of Canadian dollars) Notes GAAP (Decrease) US GAAP - ------------------------------ ------ -------- ---------- -------- Property, plant and equipment (A) $ 13,714 $ (60) $ 13,654 Current portion of other long-term assets (B) $ - $ 16 $ 16 Future income tax (A,B) $ 3,591 $ (3) $ 3,588 Shareholders' equity $ 6,009 $ (41) $ 5,965
Notes: (A) Using Canadian full cost accounting rules, costs capitalized in each cost centre, net of future income taxes, are limited to an amount equal to the undiscounted, future net revenues from proved reserves using estimated future prices and costs, plus the carrying amount of unproved properties and major development projects (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 based on prices and costs as at the balance sheet date and are discounted at 10%. (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 also uses interest rate swaps to manage its interest rate exposure. Effective January 1, 2004, the Company prospectively adopted Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-hedging Derivative Financial Instruments" for Canadian GAAP. Under Canadian GAAP, unrealized derivative financial instruments not designated as hedges are recorded in the consolidated financial statements at their fair value. Changes in the fair value of the undesignated derivative financial instruments in subsequent periods are recognized in consolidated net earnings. Derivative financial instruments designated as hedges are not recorded in the consolidated financial statements until realized. There is no requirement to recognize an ineffective portion of derivative financial instruments designated 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 which case the changes are recognized in comprehensive income. In 2003 and 2002, 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 $8 million, net of future income tax recoveries of $3 million, was reclassified to net earnings during 2004 (2003 - a loss of $20 million, net of future income tax recoveries of $9 million; 2002 - a loss of $31 million, net of future income tax recoveries of $15 million). 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. 89 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT (C) Under Canadian GAAP, capitalization of interest on projects constructed over time is discretionary. The Company has determined that the appropriate time to begin capitalizing interest on the Horizon Project is when sanction was received in February 2005. For US GAAP, capitalization of interest on projects constructed over time is mandatory and interest has been capitalized to the costs of construction in 2004. (D) Under Canadian GAAP, when the asset retirement obligation standard was adopted prior period comparative balances were restated to reflect the effect of the new standard on that year. Under US GAAP, when the asset retirement obligation standard was adopted the cumulative effect of the new standard on prior periods was included in earnings in the year adopted. (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. 18. Recently issued accounting standards Financial Instruments In January 2005, the CICA issued Section 3855 "Financial Instruments - Recognition and Measurement". This Section prescribes when a financial asset, financial liability, or non-financial derivative is to be recognized on the balance sheet and at what amount - sometimes using fair value; other times using cost-based measures. This Section also specifies how financial instruments gains and losses are to be presented. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Transitional provisions for this Section are complex and vary based on the type of financial instruments under consideration. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Hedges In January 2005, the CICA issued Section 3865 "Hedges". This Section expands on existing Accounting Guideline 13 - Hedging Relationships, and Section 1650 "Foreign Currency Translation", by specifying how hedge accounting is applied and what disclosure are necessary when it is applied. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Retroactive application of this Section is not permitted. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Comprehensive Income In January 2005, the CICA issued Section 1530 "Comprehensive Income". This Section introduces new standards for reporting and display of comprehensive income. Comprehensive income is the change in equity (net assets) of a company during a reporting period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Financial statements of prior periods are required to be restated for certain comprehensive income items. In addition, a company is encouraged, but not required to present reclassification adjustments, in comparative financial statements provided for earlier periods. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Equity In January 2005, the CICA issued Section 3251 "Equity". This Section replaces Section 3250 "Surplus". It establishes standards for the presentation of equity and changes in equity during a reporting period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Financial statements of prior periods are required to be restated for certain specified adjustments. For all other items, comparative financial statements are presented are not restated, but an adjustment to the opening balance of accumulated other comprehensive income may be required. In addition, a company is encouraged, but not required to present reclassification adjustments, in comparative financial statements provided for earlier periods. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. 90 EX-99 4 ex-3form40f_2004.txt EXHIBIT 3 EXHIBIT 3 --------- 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS 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; the 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 asset retirement obligations; 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 (net earnings before interest, taxes, depreciation, depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, stock-based compensation expense and unrealized risk management activities). 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 ("MD&A") 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, 2004. 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 17 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 ("mcf") of natural gas to one barrel ("bbl") of oil to estimate relative energy content. 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. Production volumes are the Company's interest before royalties, and realized prices exclude the effect of risk management activities, except where noted otherwise. The following discussion and analysis refers primarily to the Company's 2004 financial results compared to 2003, unless otherwise indicated. In addition, this discussion details the Company's capital program and outlook for 2005. The fourth quarter discussion and analysis was included in the Company's fourth quarter press release. This MD&A is dated February 18, 2005. CANADIAN NATURAL 39 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT OBJECTIVE AND STRATEGY The Company's objective is to increase cash flow, 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 through 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 crude oil, Pelican Lake crude oil (1), primary heavy crude oil and thermal heavy crude 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 crude oil is 14-17 degrees API oil, but receives medium quality crude netbacks due to low operating costs and low royalty rates. The Company has expanded its hedging program in an effort to reduce the risk of volatility in commodity price markets and to underpin the Company's cashflow through the Horizon Oil Sands Project ("Horizon Project") construction period. The Company's crude oil marketing strategy includes displacing medium sour crude oil from PADD II, supporting and participating in pipeline additions, encouraging the development of projects that add conversion capacity, and blending strategy. 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. Strategic accretive acquisitions are a key component of the Company's strategy. The Company has used excess cash flows derived from higher than expected commodity prices to selectively acquire properties generating future cash flows in its core regions. These targeted acquisitions provide relatively quick repayment of initial investments and will provide additional free cash flow during the construction years of the Horizon Project while still achieving targeted returns. The acquisitions of the Petrovera Partnership ("Petrovera") and natural gas properties in North America and the acquisition of properties in the central North Sea meet these reinvestment criteria and further enhance the Company's abilities to complete the Horizon Project. This expansion of the conventional asset base also helps reduce the sole project risk exposure associated with this major oil sands development project. The Company is committed to maintaining its strong financial position throughout construction of the Horizon Project. The Company has built the necessary financial capacity to complete the Horizon Project while at the same time not compromising delivery of low-risk crude oil and natural gas growth opportunities. The year ended December 31, 2004, was another successful year in the execution of the Company's strategy. Highlights are as follows: o Achieved record levels of net earnings; o Achieved record levels of cash flow; o Achieved record levels of natural gas and crude oil and NGLs production; o Achieved the Company's annual production guidance for both natural gas and crude oil and NGLs; o Completed four strategic acquisitions including: o the acquisition of Petrovera; o the acquisition of natural gas assets located in the Company's core region of Northeast British Columbia and an extension of its core region in the Foothills area of Northwest Alberta; o the acquisition of light crude oil producing properties in the Central North Sea; o the acquisition of certain natural gas properties located in Alberta, British Columbia and Saskatchewan; o Commenced production from a new phase of the Primrose in-situ thermal crude oil development; o Filed a public disclosure document for regulatory approval of the Primrose East project; o Received regulatory approvals for the Horizon Project from the Alberta Energy and Utilities Board as well as the Alberta Provincial Cabinet and the Canadian Federal Cabinet; o Completed the subdivision of its Common Shares on the basis of two for one; o Increased the quarterly dividend by 33% to $0.10 per common share; and o Purchased 873,400 common shares for a total cost of $33 million under the Company's Normal Course Issuer Bid. 40 CANADIAN NATURAL 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS NET EARNING AND CASH FLOW FROM OPERATIONS
FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) 2004 2003(1) 2002(1) - ------------------------------------------------------------------ ------- ------- ------- Revenue, before royalties $ 7,547 $ 6,155 $ 4,459 Net earnings $ 1,405 $ 1,403 $ 539 Per common share - basic (2) $ 5.24 $ 5.23 $ 2.11 - diluted (2) $ 5.20 $ 5.06 $ 2.04 Cash flow from operations (4) $ 3,769 $ 3,160 $ 2,254 Per common share - basic (2) $ 14.06 $ 11.77 $ 8.82 - diluted (2) $ 13.98 $ 11.53 $ 8.50 Capital expenditures, net of dispositions (3) $ 4,633 $ 2,506 $ 4,069
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) Restated to reflect two-for-one share split in May 2004. (3) In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as Petrovera, for $471 million. Strategically, the acquisition fit with the Company's objective of dominating its core regions and related infrastructure. The Company achieved cost reductions through synergies with its existing facilities, including additional throughput in its 100% owned ECHO Pipeline. The acquisition is included in the results of operations commencing February 2004. In 2002, the Company paid cash of $850 million and issued 20,016,436 common shares to acquire all of the issued and outstanding common shares of Rio Alto Exploration Ltd. ("Rio Alto") by way of a plan of arrangement. This was a strategic acquisition as it increased the Company's natural gas production and added a new natural gas core region in Northwest Alberta. The Rio Alto acquisition is included in the results of operations commencing July 2002. (4) Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. The Company evaluates its performance and that of its business segments based on net earnings and cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company's ability and the ability of its business segments to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
($ millions) 2004 2003 2002 - ------------------------------------------ ------- ------- ------- Net earnings $ 1,405 $ 1,403 $ 539 Non-cash items: Depletion, depreciation and amortization 1,769 1,509 1,298 Asset retirement obligation accretion 51 62 68 Stock-based compensation 249 200 - Unrealized risk management activities (40) - - Unrealized foreign exchange gain (94) (343) (36) Deferred petroleum revenue tax (recovery) (45) (9) 10 Future income tax 474 338 375 ------- ------- ------- Cash flow from operations $ 3,769 $ 3,160 $ 2,254 ======= ======= =======
The Company achieved record levels of net earnings, cash flow from operations and production in 2004 as a result of strong operational performance combined with strong commodity prices. The strong operating results are attributable to the Company following its defined growth strategy and to the strong asset base the Company has developed over time through organic growth and accretive acquisitions. Net earnings increased in 2004 to $1,405 million ($5.24 per common share), up from $1,403 million ($5.23 per common share) in 2003 (2002 - $539 million or $2.11 per common share). The increase in net earnings in 2004 is primarily due to higher commodity prices and higher production volumes. These increases were offset by increased depletion, depreciation and amortization expense, increased stock-based compensation expense and decreased foreign exchange gains in 2004. In addition, net earnings were also impacted by the Company's risk management activities as a result of an expanded hedging program (see risk management activities and liquidity and capital resources) and one-time non recurring tax rate reductions. Cash flow from operations reached record levels in 2004. Cash flow from operations increased 19% to $3,769 million ($14.06 per common share), up from $3,160 million ($11.77 per common share) in 2003 (2002 - $2,254 million or $8.82 per common share). The increase in cash flow from operations resulted primarily from higher product prices and increased production volumes. In 2004, the Company's average price per barrel of crude oil and NGLs increased 16% to $37.99 from $32.66 in 2003 (2002 - $31.22). The Company's average natural gas price increased 5% to $6.50 per mcf from $6.21 per mcf in 2003 (2002 - $3.77 per mcf). Production volumes before royalties increased 12% to a record 513,835 boe/d, up from 458,814 boe/d in 2003 (2002 - 420,722 boe/d). The increase in production volumes was a result of organic growth and accretive acquisitions. Production of crude oil and NGLs before royalties increased 17% to 282,489 bbl/d, up from 242,392 bbl/d in 2003 (2002 -215,335 bbl/d). Natural gas production before royalties increased 7% to 1,388 mmcf/d, up from 1,299 mmcf/d in 2003 (2002 - 1,232 mmcf/d). CANADIAN NATURAL 41 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT
OPERATING HIGHLIGHTS 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl, except daily production) Daily production, before royalties (bbl/d) 282,489 242,392 215,335 Sales price (1) $ 37.99 $ 32.66 $ 31.22 Royalties 3.16 2.77 3.16 Production expense 10.05 10.28 8.45 ------------ --------- -------- Netback $ 24.78 $ 19.61 $ 19.61 ------------ --------- -------- NATURAL GAS ($/mcf, except daily production) Daily production, before royalties (mmcf/d) 1,388 1,299 1,232 Sales price (1) $ 6.50 $ 6.21 $ 3.77 Royalties 1.35 1.32 0.78 Production expense 0.67 0.60 0.57 ------------ --------- -------- Netback $ 4.48 $ 4.29 $ 2.42 ------------ --------- -------- BARREL OF OIL EQUIVALENT ($/boe, except daily production) Daily production, before royalties (boe/d) 513,835 458,814 420,722 Sales price (1) $ 38.45 $ 34.84 $ 27.02 Royalties 5.37 5.20 3.91 Production expense 7.35 7.15 5.99 ------------ --------- -------- Netback $ 25.73 $ 22.49 $ 17.12 ============ ========= ========
(1) Including transportation costs and excluding risk management activities. BUSINESS ENVIRONMENT
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- WTI benchmark price (US$/bbl) $ 41.43 $ 31.02 $ 26.11 Dated Brent benchmark price (US$/bbl) $ 38.28 $ 28.83 $ 25.01 Differential to LLB blend (US$/bbl) $ 13.44 $ 8.55 $ 6.50 Condensate benchmark price (US$/bbl) $ 41.62 $ 31.42 $ 26.00 NYMEX benchmark price (US$/mmbtu) $ 6.09 $ 5.44 $ 3.25 AECO benchmark price (C$/GJ) $ 6.43 $ 6.35 $ 3.86 US/Canadian dollar average exchange rate (US$) 0.7683 0.7135 0.6368 ====== ====== ======
World crude oil prices remained strong in 2004 due to the strong growth in world-wide demand, particularly in the United States and Asia. World crude oil prices have also been impacted by geopolitical uncertainty in several areas of the world, resulting in concerns around the supply of crude oil. World crude oil prices have been further impacted by weather related issues causing production disruptions in the United States Gulf Coast. West Texas Intermediate ("WTI") averaged US$41.43 per bbl for the year ended December 31, 2004, up 34% compared to US$31.02 per bbl in 2003 (2002 - US$26.11 per bbl). The impact of the higher WTI prices on the Company's heavier crude oil production was mitigated by wider heavy crude oil differentials, which increased 57% to US$13.44 per bbl in 2004, up from US$8.55 per bbl in 2003 (2002 - US$6.50 per bbl). Realized crude oil prices were also impacted by the strengthening Canadian dollar. North American natural gas prices remained strong due to concerns around supply and the impact of higher crude oil prices. NYMEX natural gas prices increased 12% to average US$6.09 per mmbtu in 2004, up from US$5.44 per mmbtu in 2003 (2002 - US$3.25 per mmbtu). AECO natural gas prices increased 1 % to average $6.43 per GJ in 2004, up from $6.35 per GJ in 2003 (2002 - $3.86 per GJ). 42 CANADIAN NATURAL 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS
REVENUE, BEFORE ROYALTIES PRODUCT PRICES (1) 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl) North America 33.16 $ 29.40 $ 28.77 North Sea 51.37 $ 42.00 $ 40.32 Offshore West Africa 49.05 $ 36.47 $ 40.10 Company average 37.99 $ 32.66 $ 31.22 NATURAL GAS ($/mcf) North America 6.61 $ 6.34 $ 3.79 North Sea 3.73 $ 3.03 $ 2.75 Offshore West Africa 5.25 $ 4.37 $ 4.82 Company average 6.50 $ 6.21 $ 3.77 PERCENTAGE OF REVENUE (excluding midstream revenue) Crude oil and NGLs 54% 50% 58% Natural gas 46% 50% 42% ==== ==== ====
(1) Including transportation costs and excluding risk management activities. Realized crude oil prices increased 16% to average $37.99 per bbl in 2004, up from $32.66 per bbl in 2003 (2002 - $31.22 per bbl). The increase in realized crude oil prices is a result of higher benchmark crude oil prices. The Company's realized natural gas price increased 5% to average $6.50 per mcf in 2004, up from $6.21 per mcf in 2003 (2002 - $3.77 per mcf). NORTH AMERICA North America realized crude oil prices increased 13% to average $33.16 per bbl in 2004, up from $29.40 per bbl in 2003 (2002 - $28.77 per bbl). The increase in the realized crude oil price is due mainly to higher world crude oil prices, partially offset by wider heavy crude oil differentials and the stronger Canadian dollar. The Company continues to focus on its crude oil marketing strategy, which includes development of a blending strategy, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with PADD II refiners to add incremental heavy crude oil conversion capacity. As part of an industry initiative to develop new blends of Western Canadian crude oils, the Company has access to blending capacity of up to 140 mbbl/d. The Company is contributing 123 mbbl/d of heavy crude oil blends to the Western Canadian Select ("WCS") stream, a new blend of up to 10 different crude oil streams. WCS resembles a Bow River type crude with distillation cuts approximating a natural heavy oil with premium quality asphalt characteristics. The new blend has an API of 19-22 degrees and is expected to grow, with the potential to become a new benchmark for North American markets in addition to WTI. The Company also continues to work with refiners to advance expansion of heavy crude oil conversion capacity, and is working with pipeline companies to develop new capacity to the Canadian west coast where crude cargos can be sold on a world-wide basis. North America realized natural gas prices increased 4% to average $6.61 per mcf in 2004, up from $6.34 per mcf in 2003 (2002 - $3.79 per mcf). The increase in natural gas pricing is due to the concerns around supply and the impact of higher crude oil prices. A comparison of the price received for the Company's North America production is as follows:
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Wellhead price(1) Light crude oil and NGLs (C$/bbl) $ 45.90 $ 37.59 $ 34.92 Pelican Lake crude oil (C$/bbl) $ 32.12 $ 28.05 $ 27.56 Primary heavy crude oil (C$/bbl) $ 28.99 $ 26.21 $ 27.06 Thermal heavy crude oil (C$/bbl) $ 29.00 $ 25.55 $ 25.70 Natural gas (C$/mcf) $ 6.61 $ 6.34 $ 3.79 ======= ======= =======
(1) Including transportation costs and excluding risk management activities. NORTH SEA North Sea realized crude oil prices increased 22% to average $51.37 per bbl in 2004, up from $42.00 per bbl in 2003 (2002 - $40.32 per bbl) due to higher world crude oil prices. OFFSHORE WEST AFRICA Offshore West Africa realized crude oil prices increased 34% to average $49.05 per bbl in 2004, up from $36.47 per bbl in 2003 (2002 - $40.10 per bbl) due to higher world crude oil prices. 43 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES
Changes due to CHANGES DUE TO -------------------------------------------------- ----------------------------------- ($ millions) 2002 Volumes Prices Other 2003 VOLUMES PRICES OTHER 2004 - ------------------------------------------------------------------------------------------------------------------- NORTH AMERICA Crude oil and NGLs $ 1,854 $ 55 $ 44 $ - $ 1,953 $ 342 $ 283 $ - $ 2,578 Natural gas 1,865 56 1,147 - 3,068 207 126 - 3,401 ------- ------- ------- --- ------- ------- ------- --- ------- 3,719 111 1,191 - 5,021 549 409 - 5,979 ------- ------- ------- --- ------- ------- ------- --- ------- NORTH SEA Crude oil and NGLs 592 265 16 - 873 123 227 - 1,223 Natural gas 28 19 33 - 80 5 9 - 94 ------- ------- ------- --- ------- ------- ------- --- ------- 620 284 49 - 953 128 236 - 1,317 ------- ------- ------- --- ------- ------- ------- --- ------- OFFSHORE WEST AFRICA Crude oil and NGLs 100 56 (15) - 141 13 54 - 208 Natural gas 2 13 (1) - 14 (1) 1 - 14 ------- ------- ------- --- ------- ------- ------- --- ------- 102 69 (16) - 155 12 55 - 222 ------- ------- ------- --- ------- ------- ------- --- ------- SUBTOTAL Crude oil and NGLs 2,546 376 45 - 2,967 478 564 - 4,009 Natural gas 1,895 88 1,179 - 3,162 211 136 - 3,509 ------- ------- ------- --- ------- ------- ------- --- ------- 4,441 464 1,224 - 6,129 689 700 - 7,518 MIDSTREAM 52 - - 9 61 - - 7 68 OTHER - - - - - - - 1 1 INTERSEGMENT (34) - - (1) (35) - - (5) (40) ------- ------- ------- --- ------- ------- ------- --- ------- ELIMINATIONS (1) TOTAL $ 4,459 $ 464 $ 1,224 $ 8 $ 6,155 $ 689 $ 700 3 $ 7,547 ------- ------- ------- --- ------- ------- ------- --- -------
(1) Eliminates internal transportation and electricity charges. Revenue rose 23% to $7,547 million in 2004, up from $6,155 million in 2003 (2002 - $4,459 million). In 2004, 20% of the Company's crude oil and natural gas revenue was generated outside of North America, up from 18% in 2003 (2002 - 16%). North Sea accounted for 17% of revenue in 2004 and 16% in 2003 (2002 - 14%), and Offshore West Africa accounted for 3% of revenue in 2004 and 2% in 2003 (2002 - 2%). The Company's production composition, before royalties, is as follows: DAILY PRODUCTION, BEFORE ROYALTIES
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS (bbl/d) North America 206,225 174,895 169,675 North Sea 64,706 56,869 38,876 Offshore West Africa 11,558 10,628 6,784 ------- ------- ------- 282,489 242,392 215,335 ------- ------- ------- NATURAL GAS (mmcf/d) North America 1,330 1,245 1,204 North Sea 50 46 27 Offshore West Africa 8 8 1 ------- ------- ------- 1,388 1,299 1,232 ------- ------- ------- TOTAL BARREL OF OIL EQUIVALENT (boe/d) 513,835 458,814 420,722 ------- ------- ------- PRODUCT MIX Light crude oil and NGLs 24% 25% 21% Pelican Lake crude oil 4% 5% 7% Primary heavy crude oil 19% 15% 14% Thermal heavy crude oil 8% 8% 9% Natural gas 45% 47% 49% ------- ------- -------
44 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS DAILY PRODUCTION, NET OF ROYALTIES
2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS (bbl/d) North America 180,011 152,444 149,485 North Sea 64,598 56,928 36,654 Offshore West Africa 11,221 10,314 6,554 ------- ------- ------- 255,830 219,686 192,693 ------- ------- ------- NATURAL GAS (mmcf/d) North America 1,048 976 949 North Sea 50 46 27 Offshore West Africa 7 8 1 ------- ------- ------- 1,105 1,030 977 ------- ------- ------- TOTAL BARREL OF OIL EQUIVALENT (boe/d) 440,022 391,361 355,611 ------- ------- -------
Daily production and per barrel statistics are presented throughout the MD&A on a "before royalty" or "gross" basis. Production net of royalties is presented above for information purposes only. The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely natural gas, light crude oil and NGLs, Pelican Lake crude oil, primary heavy crude oil and thermal heavy crude oil. The Company achieved record levels of production on a barrel of oil equivalent basis in 2004. Production before royalties on a barrel of oil equivalent basis increased 12% to average 513,835 boe/d in 2004, up from 458,814 boe/d in 2003 (2002 - 420,722 boe/d). The production volumes increased as a result of the Company's successful capital expenditure program and the acquisition of certain resource properties in the Company's North America and North Sea segments. Total crude oil and NGLs production before royalties increased 17% or 40,097 bbl/d to average 282,489 bbl/d, up from 242,392 bbl/d in 2003 (2002 - 215,335 bbl/d). Crude oil and NGLs production before royalties in 2004 increased from the previous year in all segments and was in line with production guidance provided. Natural gas production before royalties continues to represent the Company's largest product offering, accounting for 45% of the Company's total production in 2004 compared to 47% of total production in 2003 (2002 - 49%). Natural gas production before royalties increased 7% or 89 mmcf/d to average 1,388 mmcf/d, up from 1,299 mmcf/d in 2003 (2002 - 1,232 mmcf/d). Natural gas production was in line with production guidance provided. The Company expects annual production levels before royalties in 2005 to average 1,448 to 1,510 mmcf/d of natural gas and 307 to 335 mbbl/d of crude oil and NGLs. First quarter 2005 production guidance before royalties is 1,400 to 1,482 mmcf/d of natural gas and 269 to 290 mbbl/d of crude oil and NGLs. NORTH AMERICA Crude oil and NGLs production before royalties in North America increased 18% or 31,330 bbl/d to average 206,225 bbl/d in 2004, up from 174,895 bbl/d in 2003 (2002 - 169,675 bbl/d) due to the development of the Primrose thermal crude oil project and accretive acquisitions. North American natural gas production before royalties in 2004 increased 7% or 85 mmcf/d to average 1,330 mmcf/d, up from 1,245 mmcf/d in 2003 (2002 - 1,204 mmcf/d). North American production of natural gas increased as a result of organic growth and accretive property acquisitions. Production of natural gas was impacted by the shut in of 11 mmcf/d of natural gas in the Athabasca Wabiskaw-McMurray oil sands area effective July 1, 2004. NORTH SEA Crude oil production before royalties from the North Sea increased 14% or 7,837 bbl/d to average 64,706 bbl/d in 2004, up from 56,869 bbl/d in 2003 (2002 - 38,876 bbl/d). The increase in production was due to the ongoing drilling, recompletion and waterflood optimization program at the Ninian and Murchison Fields and the acquisition of light crude oil producing properties in the Central North Sea in the third quarter of 2004. Crude oil production before royalties in the fourth quarter was down primarily due to an unplanned extended shutdown on the Ninian North Platform. The shutdown was required to repair a power turbine used to drive water injection resulting in a loss of pressure to the reservoir. Remedial work was completed in early 2005 and production is recovering. Natural gas production before royalties in the North Sea increased 9% or 4 mmcf/d to average 50 mmcf/d in 2004, up from 46 mmcf/d in 2003 (2002 - 27 mmcf/d). The increase in production was due to the acquisition of properties in the Central North Sea in the third quarter of 2004 and the increased working interests acquired in the Banff Field during 2003. The increase was partially offset by the commencement of the natural gas reinjection program in the Banff Field in the fourth quarter of 2004. Despite some delays and production interruptions during commissioning, results to date are positive with full production benefit expected to commence during the second quarter of 2005. Natural gas production in the North Sea is expected to decline in 2005 due to the natural gas reinjection program in the Banff Field. 45 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT OFFSHORE WEST AFRICA Offshore West Africa crude oil production before royalties for the year ended December 31, 2004 increased 9% or 930 bbl/d to average 11,558 bbl/d, up from 10,628 bbl/d in 2003 (2002 - 6,784 bbl/d) due to the perforation of the upper zone of the East Espoir Field in the third quarter of 2003 and the completion of the fourth water injection well and two additional producing wells during 2003. Natural gas production before royalties in Offshore West Africa remained constant at 8 mmcf/d in 2004 and 2003 (2002 - 1 mmcf/d). ROYALTIES
2004 2003 2002 - --------------------------------------------------------------------------------- CRUDE OIL AND NGLs ($/bbl) North America $ 4.21 $ 3.79 $ 3.42 North Sea $ 0.08 $ (0.03) $ 2.30 Offshore West Africa $ 1.43 $ 1.08 $ 1.35 Company average $ 3.16 $ 2.77 $ 3.16 NATURAL GAS ($/mcf) North America $ 1.40 $ 1.38 $ 0.80 North Sea $ - $ - $ - Offshore West Africa $ 0.15 $ 0.13 $ 0.15 Company average $ 1.35 $ 1.32 $ 0.78 COMPANY AVERAGE ($/BOE) $ 5.37 $ 5.20 $ 3.91 PERCENTAGE OF REVENUE(1) Crude oil and NGLs 8% 9% 10% Natural gas 21% 21% 21% Boe 14% 15% 14%
(1) Including transportation costs and excluding risk management activities. NORTH AMERICA Crude oil and NGLs royalties in North America increased to $4.21 per bbl, up from $3.79 per bbl in 2003 (2002 - $3.42 per bbl) due to higher benchmark crude oil prices. Natural gas royalties in North America increased to $1.40 per mcf, up from $1.38 per mcf in 2003 (2002 - $0.80 per mcf). Natural gas royalties as a percentage of revenue fluctuate as a result of fluctuations in natural gas prices and the strong correlation of royalties to natural gas prices. NORTH SEA North Sea crude oil royalties increased to $0.08 per bbl, up from a recovery of $(0.03) per bbl in 2003 (2002 - $2.30 per bbl). North Sea government royalties on crude oil were eliminated effective January 1, 2003. The remaining North Sea royalty represents a gross overriding royalty on the Ninian Field. In 2003, the Company received a refund of royalties previously provided. OFFSHORE WEST AFRICA Offshore West Africa crude oil royalties increased to $1.43 per bbl, up from $1.08 per bbl in 2003 (2002 - $1.35 per bbl) due to fluctuations in realized crude oil prices. Offshore West Africa production is governed by the terms of the Production Sharing Contract ("PSC"). Under the PSC, revenues are divided into cost recovery revenue and profit revenue. Cost recovery revenue allows the Company to recover the capital and operating costs carried by the Company on behalf of the Government State Oil Company. These revenues are reported as sales revenue. Profit revenue is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Government. The Government's share of revenue attributable to the Company's equity interest is reported as either royalty expense or current income tax expense in accordance with the PSC. 46 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS PRODUCTION EXPENSE
2004 2003 2002 - ----------------------------------------------------------------- CRUDE OIL AND NGLs ($/bbl) North America $ 8.94 $ 9.14 $ 6.73 North Sea $ 14.03 $ 14.07 $ 15.06 Offshore West Africa $ 7.59 $ 8.68 $ 13.63 Company average $ 10.05 $ 10.28 $ 8.45 NATURAL GAS ($/mcf) North America $ 0.62 $ 0.57 $ 0.55 North Sea $ 2.07 $ 1.33 $ 1.53 Offshore West Africa $ 1.33 $ 1.39 $ 1.81 Company average $ 0.67 $ 0.60 $ 0.57 COMPANY AVERAGE ($/BOE) $ 7.35 $ 7.15 $ 5.99
Production expense increased to $7.35 per boe in 2004, up from $7.15 per boe in 2003 (2002 - $5.99 per boe). Crude oil and NGLs production expense decreased to $10.05 per bbl in 2004, down from $10.28 per bbl in 2003 (2002 - $8.45 per bbl). Natural gas production expense for the year 2004 increased to $0.67 per mcf, up from $0.60 per mcf in 2003 (2002 - $0.57 per mcf). NORTH AMERICA North American crude oil and NGLs production expense decreased 2% to average $8.94 per bbl, down from $9.14 per bbl in 2003 (2002 - $6.73 per bbl). The decrease was primarily due to the impact of a lower steam oil ratio for the Company's thermal heavy crude oil operations, resulting in a lower cost per barrel for fuel used in the generation of steam. North American natural gas production expense per mcf increased 9% to average $0.62 per mcf, up from $0.57 per mcf in 2003 (2002 - $0.55 per mcf). The increase is partly due to increased activity in the oil and gas sector in reaction to higher commodity prices, which resulted in higher production expense, especially as the labour market tightened, and partly due to increased production in certain areas such as Northeast British Columbia where the Company is incurring higher costs associated with third party processing and gathering. In addition, the cost of steel products increased in 2004 due to increased global demand. NORTH SEA North Sea crude oil production expense decreased in 2004 to $14.03 per bbl, down from $14.07 per bbl in 2003 (2002 - $15.06 per bbl). North Sea crude oil production expense varied on a per barrel basis due to the timing of maintenance work and the changes in production volumes on a relatively fixed cost base. OFFSHORE WEST AFRICA Offshore West Africa crude oil production expense decreased to $7.59 per bbl, down from $8.68 per bbl in 2003 (2002 - $13.63 per bbl), resulting from production increases in the Espoir Field. The Espoir Field commenced operations in the first quarter of 2002. Offshore West Africa crude oil production expenses are largely fixed in nature and therefore fluctuate on a per barrel basis from the comparable periods due to changes in production from the Espoir Field. MIDSTREAM
($ MILLIONS) 2004 2003 2002 - ----------------------------------------------------------- Revenue $68 $61 $52 Production expense 20 $15 $14 Midstream cash flow 48 $46 $38 Depreciation 7 $ 7 $ 8 Segment earnings before taxes $41 $39 $30
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 80% of the Company's heavy crude oil production was transported to the international mainline 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. 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 crude oil. 47 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Revenue from the midstream assets increased 11% to $68 million, up from $61 million in 2003 (2002 - $52 million). The increase in revenue, operating cash flow and segment earnings before taxes was due to the expansion of the ECHO Pipeline. The expansion of the ECHO Pipeline was completed in October 2003 and increased capacity to 72 mbbl/d from 58 mbbl/d. DEPLETION, DEPRECIATION AND AMORTIZATION(2)
($ millions, except per boe amounts) 2004 2003(1) 2002(1) - ------------------------------------------------------------------------------------------------------------------------------ North America $ 1,444 $ 1,209 $ 1,022 North Sea 265 $ 252 $ 188 Offshore West Africa 53 $ 41 $ 80 Expense $ 1,762 $ 1,502 $ 1,290 $/boe $ 9.37 $ 8.96 $ 8.40 ========== ========== =========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) DD&A excludes depreciation on midstream assets. Depletion, depreciation and amortization ("DD&A") increased in total and per boe to $1,762 million or $9.37 per boe, up from $1,502 million or $8.96 per boe in 2003 (2002 - $1,290 million or $8.40 per boe). The increase in DD&A was due to higher finding and development costs associated with natural gas exploration in North America, the allocation of the acquisition costs associated with recent acquisitions, the fair value of future abandonment costs associated with the acquisition of additional properties in the North Sea, and higher costs to develop the Company's proved undeveloped reserves. In 2003, DD&A included the write-off of $12 million of costs associated with the Company's exploration activity in offshore France. In 2002, DD&A included the write-off of $51 million as a result of the Company's decision to exit from its interests in Block 19, Angola, and from the Aje Field, Nigeria. ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts) 2004 2003(1) 2002(1) - --------------------------------------------------------------------------------------------------- North America $ 28 $ 26 $ 20 North Sea $ 22 $ 36 $ 48 Offshore West Africa $ 1 $ - $ - Expense $ 51 $ 62 $ 68 $/boe $ 0.27 $ 0.37 $ 0.44 ======== ======== ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). Accretion expense is the increase in the carrying amount of the asset retirement obligation due to the passage of time. ADMINISTRATION EXPENSE
($ millions, except per boe amounts) 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Gross cost $ 315 $ 262 $ 147 $/boe $ 1.68 $ 1.57 $ 0.96 Net expense $ 115 $ 87 $ 61 $/boe $ 0.61 $ 0.52 $ 0.40 =========== ======== ========
Gross administration expense increased to $1.68 per boe, up from $1.57 per boe in 2003 (2002 - $0.96 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 in 2003. 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 $0.61 per boe in 2004, up from $0.52 per boe in 2003 (2002 - $0.40 per boe). 48 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS STOCK-BASED COMPENSATION
($ millions, except per boe amounts) 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Stock option plan $ 249 $ 200 $ - Share bonus plan 10 $ - $ - Stock-based compensation expense $ 259 $ 200 $ - $/boe $ 1.37 $ 1.20 $ - =========== ======== =======
The Company's Stock Option Plan (the "Option Plan") 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. The Option Plan balances 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 fair 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. The Company has recorded a liability at December 31, 2004 of $323 million compared to $171 million at December 31, 2003 for expected cash settlements of stock options based on the fair 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). The liability is revalued to reflect changes in the market price of the Company's common shares and the net change is recognized in net earnings. The stock-based compensation expense relating to the Company's Option Plan in 2004 is $249 million ($168 million after tax), up from $200 million ($136 million after tax) in 2003. In 2004, the Company paid $80 million for stock options surrendered for cash settlement compared to $31 million in 2003. The Share Bonus Plan incorporates share ownership in the Company by its employees without the granting of stock options or the dilution of current Shareholders. Under the plan, a cash bonus may be awarded based on the Company's and the employee's performance and subsequently used by a trustee to acquire common shares of the Company. The common shares vest to the employee over a three-year period provided the employee does not leave the employment of the Company. If the employee leaves the employment of the Company, the unvested common shares are forfeited under the terms of the plan. In 2004, the Company recognized $10 million ($6 million after tax) of compensation expense under the Share Bonus Plan. INTEREST EXPENSE
($ millions, except per boe amounts and interest rates) 2004 2003(1) 2002(1) - -------------------------------------------------------------------------------------------------------------------------- Interest expense $ 189 $ 201 $ 203 $/boe $ 1.01 $ 1.20 $ 1.26 Average effective interest rate 5.2% 5.8% 5.5% === === ===
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). Interest expense decreased to $189 million in 2004, down from $201 million in 2003 (2002 - $203 million) due mainly to a lower average effective interest rate of 5.2%, down from 5.8% in 2003 (2002 - 5.5%). In addition, the strengthening Canadian dollar reduced the Canadian equivalent interest expense on the Company's US dollar denominated debt. The Company continues to benefit from the lower short-term interest rates as its fixed-rate debt accounts for only 43% of total debt outstanding after interest rates swaps (see note 12 to the consolidated financial statements) as at December 31, 2004 (2003 - 32%, 2002 - 40%). Interest expense was impacted by the Company prospectively adopting the Canadian Institute of Chartered Accountants' ("CICA") Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments." As a result of the adoption of this accounting guideline, $32 million of realized gains on certain of its fixed to floating interest rate swaps are included in risk management activities in 2004 (2003 - $35 million, 2002 - $34 million). Interest expense decreased on a total and boe basis in 2004 from 2003 mainly due to lower borrowing rates. 49 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT RISK MANAGEMENT ACTIVITIES On January 1, 2004, the Company prospectively adopted the CICA's Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments". Financial instruments that do not qualify as hedges under the Guideline or are not designated as hedges are recorded at fair value on the Company's consolidated balance sheet, with subsequent changes in fair value recognized in net earnings. The Company utilizes various financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are not used for trading or speculative purposes. The Company enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to protect cash flow for capital expenditure programs. The Company also enters into foreign currency denominated financial instruments to manage future US dollar denominated crude oil and natural gas sales. Gains or losses on these contracts are included in risk management activities. 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 contracts require the periodic exchange of payments without the exchange of the notional principal amount on which the payments are based. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. Gains or losses on interest rate contracts not designated as hedges are included in risk management activities. The Company enters into cross currency swap agreements to manage its fixed to floating interest rate mix on long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense. Gains or losses on the termination of financial instruments that have been accounted for as hedges are deferred under other long-term assets or liabilities on the consolidated balance sheets and amortized into 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. Adoption of this Guideline and EIC 128 had the following effects on the Company's consolidated financial statements:
($ millions) 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------------ REALIZED LOSS (GAIN) Crude oil and NGLs financial instruments $ 501 $ 95 $ 114 Natural gas financial instruments 5 88 3 Interest rate swaps (32) (35) (34) ----------- --------- -------- $ 474 $ 148 $ 83 ----------- --------- -------- UNREALIZED LOSS (GAIN) Crude oil and NGLs financial instruments $ (47) $ - $ - Natural gas financial instruments - - - Interest rate swaps 7 - - ----------- --------- -------- $ (40) $ - $ - ----------- --------- -------- TOTAL $ 434 $ 148 $ 83 =========== ======== =======
The effect of the realized loss from crude oil and NGLs and natural gas financial instruments was to reduce the Company's average realized prices as follows:
2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------------ Crude oil and NGLs($/bbl) $ 4.85 $ 1.07 $ 1.46 Natural gas ($/mcf) $ 0.01 $ 0.19 $ 0.01 =========== ========= ========
The effect of the realized gain on interest rate swaps on the Company's interest expense was:
($ millions, except interest rates) 2004 2003(1) 2002(1) - ------------------------------------------------------------------------------------------------------------------------------ Interest expense as per the financial statements $ 189 $ 201 $ 203 Less: realized risk management gain (32) (35) (34) ------------ --------- -------- $ 157 $ 166 $ 169 =========== ========= ======== Average effective interest rate 4.4% 4.8% 4.8% =========== ========= ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). 50 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS FOREIGN EXCHANGE
($ millions) 2004 2003(1) 2002(1) - ------------------------------------------------------------------------------------------------------------------------------ Realized foreign exchange loss $ 3 $ 8 $ 4 Unrealized foreign exchange gain (94) (343) (36) Total $ (91) $ (335) $ (32) =========== ======= ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). The majority of the unrealized foreign exchange gain is related to the fluctuation of the Canadian dollar in relation to the US dollar. The Canadian dollar ended the year 2004 at US$0.8308 compared to US$0.7738 at December 31, 2003 (December 31, 2002 - US$0.6331). The majority of the Company's borrowings are denominated in US dollars. At December 31, 2004, the Company's US dollar denominated debt amounted to US$2,969 million compared to US$2,045 million in 2003 (2002 - US$2,048 million). US dollar denominated debt represented 77% of total debt outstanding at December 31, 2004 (2003 - 85%, 2002 - 77%). Due to the higher proportion of US dollar denominated debt outstanding, the Company's net earnings are more sensitive to fluctuations in the Canadian dollar. In order to mitigate a portion of the volatility associated with the Canadian dollar, the Company has designated certain US dollar denominated debt as a hedge against its net investment in US dollar based self-sustaining foreign operations. Accordingly, translation gains and losses on this US dollar denominated debt are included in the foreign currency translation adjustment in shareholders' equity in the consolidated balance sheets. The Company's realized product prices are sensitive to currency exchange rates. Recent increases in the value of the Canadian dollar in relation to the US dollar had a negative impact on the Company's commodity prices realized (see Sensitivity Analysis). TAXES
($ millions, except income tax rates) 2004 2003 2002 - ------------------------------------------------------------------------------ TAXES OTHER THAN INCOME TAX Current $ 210 $ 116 $ 53 Deferred (45) $ (9) $ 10 Total $ 165 $ 107 $ 63 CURRENT INCOME TAX North America - Current income tax $ 89 $ 43 $ - North America - Large Corporations Tax $ 11 $ 16 $ 21 North Sea $ 2 $ 23 $ (19) Offshore West Africa $ 13 $ 10 $ 6 Other $ 1 $ - $ - Total $ 116 $ 92 $ 8 FUTURE INCOME TAX (1) $ 474 $ 338 $ 375 EFFECTIVE INCOME TAX RATE (1) 29.6% 23.5% 41.6% ==== ==== ====
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). 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 $165 million or $0.88 per boe in 2004, up from $107 million or $0.64 per boe in 2003 (2002 - $63 million or $0.41 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 $145 million or $0.77 per boe in 2004 compared to $97 million or $0.58 per boe in 2003 (2002 - $51 million or $0.33 per boe). 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 and will vary depending upon the amount of capital expenditures incurred in Canada and the way it is deployed. No current income tax provision was required for North America in 2002. The Company is liable for the payment of Federal Large Corporations Tax ("LCT"). LCT decreased to $11 million or $0.09 per boe from $16 million or $0.14 per boe (2002 - $21 million or $0.11 per boe) as a result of the Company being taxable and a partial offset available in the calculation of the Federal corporate surtax. In addition, the LCT rate was reduced from 0.225% to 0.2% in 2004 as part of the phased elimination of LCT over five years. 51 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT It is anticipated that, based on the current availability of approximately $4.5 billion of tax pools in Canada at the end of 2004 and current commodity strip prices, the Company will be cash taxable in Canada in 2005 in the amount of $200 million to $300 million. Current income tax in the North Sea decreased to $2 million or $0.01 per boe, down from $23 million or $0.14 per boe in 2003 (2002 - recovery of $19 million or $0.13 per boe). The decrease in the current income tax expense was due to tax pools acquired in the recent acquisition being immediately deductible. 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 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%. The Company's future income tax provision for 2004 increased to $474 million ($2.53 per boe), up from $338 million ($2.02 per boe) in 2003 (2002 - $375 million or $2.45 per boe). In 2004 the North America future income tax liability was reduced by $66 million as a result of a reduction in the Alberta corporate income tax rate (2003 - $31 million, 2002 - $21 million). In 2003, the Federal Government introduced legislation to reduce the corporate income tax rate on income from resource activities 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 the Federal tax rate reductions, the future income tax liability in North America was decreased by $247 million in 2003. In 2002, the future income tax liability in the North Sea was increased by $34 million as a result of the introduction of a 10% supplementary charge on profits from North Sea crude oil and natural gas production. The following table shows the effect of non-recurring benefits on income taxes:
($ millions, except income tax rates) 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------------- Income tax as reported Current income tax $ 116 $ 92 $ 8 Future income tax expense(1) $ 474 $ 338 $ 375 ----------- -------- -------- $ 590 $ 430 $ 383 Alberta corporate tax rate reduction $ 66 $ 31 $ 21 Federal corporate tax rate reduction $ - $ 247 $ - UK supplementary tax on profits $ - $ - $ (34) ----------- -------- -------- Total $ 656 $ 708 $ 370 =========== ======== ======== Expected effective income tax rate 32.9% 38.6% 40.2% =========== ======== ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). CAPITAL EXPENDITURES
($ millions) 2004 2003 2002 - -------------------------------------------------------------------------------- EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT Net property acquisitions(1) $1,835 336 2,833 Land acquisition and retention 120 154 114 Seismic evaluations 89 77 63 Well drilling, completion and equipping 1,394 1,194 626 Pipeline and production facilities 821 522 292 ------ ----- ----- TOTAL NET RESERVE REPLACEMENT EXPENDITURES 4,259 2,283 3,928 Horizon Oil Sands Project 291 152 68 Midstream 16 11 20 Abandonments 32 40 43 Head office 35 20 10 ------ ----- ----- TOTAL NET CAPITAL EXPENDITURES $4,633 2,506 4,069 ====== ===== ===== BY SEGMENT North America $3,355 1,769 3,420 North Sea 608 338 323 Offshore West Africa 296 176 185 Horizon Project 291 152 68 Midstream 16 11 20 Abandonments 32 40 43 Head office 35 20 10 ------ ----- ----- TOTAL $4,633 2,506 4,069 ====== ===== =====
(1) Includes Business Combinations. 52 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The Company's strategy is focused on building a diversified asset base that is balanced between various products. The capital expenditures program continues to reflect this strategy. In 2004, capital expenditures were $4,633 million, including the acquisition of Petrovera, compared to $2,506 million in 2003 (2002 - $4,069 million including the acquisition of Rio Alto). The increase in capital expenditures was a result of property acquisitions made in the North America and North Sea segments. The Company continues to make significant progress on its larger, future-growth projects while maintaining its focus on existing assets. The Company's drilling activity decreased 19% with the drilling of 1,449 net wells compared to 1,793 net wells drilled in 2003 (2002 - 900 net wells). The Company drilled 689 net natural gas wells, down 11 % from the 777 net wells in 2003 (2002 - 162 net wells) and 328 net crude oil wells, down 28% from the 458 net wells in 2003 (2002 - 264 net wells). In addition, during 2004 the Company drilled 336 net stratigraphic test/service wells primarily on the oil sands leases in the Horizon Project and in the Northern Plains core region, down 24% from the 440 net wells in 2003 (2002 - 447 net wells), and 96 net wells that were dry and abandoned, down 19% from the 118 net wells in 2003 (2002 - 27 net wells). The total number of wells drilled decreased from the prior year due to the reallocation of capital resulting from the strategic acquisitions completed in 2004. The Company achieved an overall success rate of 91%, excluding stratigraphic test and service wells. These excellent results reflect the disciplined approach that the Company takes in its exploitation and development programs and the strength of its asset base. NORTH AMERICA North America accounted for 80% of the total capital expenditures in 2004 compared to 79% in 2003 (2002 - 86%). In 2004, the Company drilled 689 net natural gas wells, including 163 net wells in the Northern Plains core region, 221 net wells in the Southern Plains core region targeting shallow gas, 138 net wells in Northwest Alberta and 167 net wells in Northeast British Columbia. The Company also drilled 317 net crude oil wells in 2004. These wells were concentrated in the Company's Northern Plains crude oil region where 238 net heavy crude oil wells were drilled. Included in this figure were 58 net high-pressure horizontal thermal crude oil wells that were drilled and completed at Primrose as part of the 2004 development strategy of the area. As part of the development of the Company's heavy crude oil resources, the Company is continuing with its Primrose thermal project, which includes the Primrose North expansion project and drilling additional wells in the Primrose South project to augment existing production. At Primrose South, production was commissioned from the two new phases that commenced construction in 2003. The Primrose North expansion continues to be on track and on budget with total capital expenditures of approximately $300 million expected to be incurred, leading to first oil of 30 mbbl/d in 2006. Late in the third quarter, the Company filed a public disclosure document for regulatory approval of its Primrose East project, a new facility located about 15 kilometres from its existing Primrose South steam plant and 25 kilometres from its Wolf Lake central processing facility. Once completed, Primrose East will be fully integrated with existing operations at Wolf Lake, Primrose South and Primrose North. The Company currently expects to complete its regulatory application by late 2005 with a regulatory decision expected in late 2006. The Pelican Lake enhanced crude oil recovery project continues on track. The waterflood has provided initial production increases as expected and has shown positive waterflood response. The waterflood project will be expanded in 2005 and the Company plans to enhance the process by use of a polymer flood. The polymer flood pilot will commence during 2005 with three injectors and five producers. In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as Petrovera, for $471 million. Strategically, the acquisition fit with the Company's objective of dominating its core regions and related infrastructure. The Company achieved cost reductions through synergies with its existing facilities, including additional throughput in its 100% owned ECHO Pipeline. The acquisition is included in the results of operations commencing February 2004. In the second quarter of 2004, the Company completed the acquisition of certain resource properties located in Northeast British Columbia and Northwest Alberta for $280 million. These properties include a further ownership interest in the Ladyfern natural gas field. In addition, the Company acquired undeveloped pools with significant natural gas potential in deeper zones and will add a new exploration base in the Alberta Foothills. In the fourth quarter of 2004, the Company completed the acquisition of certain resource properties located in Alberta, British Columbia and Saskatchewan for $703 million. The acquisition also includes over 510,000 net acres of unproven land. The acquisition has been included in operations effective December 2004. The acquisition fits the Company's strategy of dominating its core regions and related infrastructure, as the vast majority of the properties acquired are located within its core regions. The acquisition extends the Company's Northern Plains core region into the light crude oil operating area of Dawson. During the fourth quarter, the Company increased capital spending levels directed toward natural gas drilling in an effort to reduce pressures of a tight 2005 winter drilling season by starting earlier. This effort included a detailed and sequential drilling program that facilitated the procurement of better drilling rigs and crews for the winter season, both of which are an integral part of cost control. Certain portions of the drilling program were delayed due to warmer than expected weather through mid-December; however, the Company still expects to complete the majority of its plan. 53 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Midstream The Cold Lake Pipeline Limited Partnership, in which the Company has a 15% working interest, completed the construction of new facilities to allow shipment of up to 60,000 bbl/d of DilSynBit product. The new DilSynBit product will include light synthetic oil as a blending component to dilute the heavy, tar-like Cold Lake bitumen. The DilSynBit project will involve construction of two 80,000 barrel storage tanks, pumping facilities and metering equipment on the Cold Lake system. Horizon The third phase of the front-end engineering for the Horizon Project, Engineering Design Specification ("EDS"), was completed and ongoing detail work continues. The EDS provided sufficient definition for a lump sum inquiry for the detailed Engineering, Procurement and Construction ("EPC") of the various project components. The EDS also provided a detailed cost estimate and the basis upon which management made the final recommendation to the Board of Directors for sanction of the Horizon Project. The Company received regulatory approvals from the Alberta Energy and Utilities Board as well as the Alberta Provincial Cabinet and the Federal Cabinet in the first quarter of 2004. In the fourth quarter, site preparation work continued as well as work on the construction of onsite access roads, camps and the installation of deep underground facilities such as electrical, natural gas, water and sewage. In addition, clarification of bid documents occurred, resulting in the Company being able to obtain approximately 68% of Phase 1 costs on a fixed cost basis. The current estimate for Phase 1 construction costs now totals approximately $6.8 billion, including a contingency reserve of $700 million. The total cost for all three phases of the Horizon Project is now expected to be approximately $10.8 billion. On February, 9, 2005, the Board of Directors unanimously authorized management to proceed with Phase 1 of the Horizon Project. North Sea The Company continued with its planned program of infill drilling, recompletions, workovers and waterflood optimizations. During 2004, the Company commenced development drilling of the Lyell Field and the infill drilling program at the Ninian Field continued. In addition, one production and one injection well were completed at the Columba B terrace, and the Playfair well was completed in the fourth quarter with a production rate of 5 mbbl/d and sufficient associated natural gas to provide the Murchison Platform energy needs, thereby reducing production costs. During the third quarter of 2004, the Company acquired certain light crude oil producing properties in the Central North Sea. The acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields), together with associated production facilities, including a fixed platform Floating Production Vessel ("FPV") and adjacent exploration acreage. The Company equity interests in the producing fields acquired are: T-Block Tiffany, Toni and Thelma 100.00% B-Block Balmoral 70.20% Glamis 75.29% Stirling 68.68% The Company continued with the implementation of the natural gas reinjection project at the Banff Field in the Central North Sea, with reinjection commencing in November 2004. The project is expected to increase the overall reservoir recovery of crude oil, but will result in reductions in natural gas volumes. Offshore West Africa Offshore West Africa capital expenditures include the development of the Baobab Field where drilling is ongoing. To date, production testing on four producer wells has met or exceeded expectations. In addition, the Floating Production, Storage and Offtake Vessel ("FPSO") has been completed and is now moored on location. During the fourth quarter of 2004, the Acajou North exploration well was drilled to delineate the extent of the previously drilled Acajou discovery. The result of this well did not yield sufficient hydrocarbons to merit a stand alone development at Acajou. However, this field is being evaluated for future tie-back to East Espoir. At Zaizou, an exploration well spudded late in the fourth quarter was unsuccessful and the data obtained from this well is currently being used to trace the pattern of oil migration in the area to help identify future exploration targets. The planned development of the nearby West Espoir Field was sanctioned by partners with various components out for bid. The development is progressing on schedule and is expected to commence production in mid 2006 through existing FPSO facilities. Finally, additional review of seismic and geological data on Block 16 located offshore Angola indicates that while significant upside remains a possibility, its risk level is outside the normal operating parameters of the Company. As a result, the Company continues to evaluate alternatives for its holdings in the Block. 54 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS Liquidity and capital resources
($ millions, except ratios) 2004 2003(1) 2002(1) - --------------------------- -------- -------- -------- Working capital deficit (2) $ 652 $ 505 $ 14 Long-term debt $ 3,538 $ 2,748 $ 4,200 ------- ------- ------- Shareholders' equity Share capital $ 2,408 $ 2,353 $ 2,304 Retained earnings 4,922 3,650 2,424 Foreign currency translation adjustment (6) 3 26 ------- ------- ------- Total $ 7,324 $ 6,006 $ 4,754 ======= ======= ======= Debt to cash flow (2)(3) 1.0x 0.9x 1.9x Debt to EBITDA (2)(3) 0.9x 0.8x 1.7x Debt to book capitalization (2) 33.8% 32.8% 47.1% Debt to market capitalization (2) 21.4% 25.1% 40.3% After tax return on average common shareholders' equity (3) 21.4% 25.6% 13.0% After tax return on average capital employed (2)(3) 15.3% 17.1% 8.8%
- ------------ (1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) Includes current portion of long-term debt. (3) Based on trailing 12-month activity. At December 31, 2004, the working capital deficit amounted to $652 million and includes the current portion of other long-term liabilities of $260 million, consisting of stock based compensation of $243 million and the mark to market valuation of certain Risk Management financial derivative instruments of $17 million. The settlement of the stock-based compensation liability is dependant upon the surrender of vested stock options for cash settlement by employees and the value of the Company's share price at the time of surrender. The settlement of the Risk Management financial derivative instruments is primarily dependant upon the underlying crude oil and natural gas prices at the time of settlement of the financial derivative instrument, as compared to the value at December 31, 2004. The Company is committed to maintaining its strong financial position throughout construction of the Horizon Project. In 2004, strong operational results and strong commodity prices enabled the Company to maintain debt levels at 33.8% of book capitalization. The Company has built the necessary financial capacity to complete the Horizon Project while at the same time not compromising delivery of low-risk conventional oil and natural gas growth opportunities. The financing of the first phase of the Horizon Project development will be guided by the competing principles of retaining as much direct ownership interest as possible while maintaining a strong balance sheet. Existing proved development projects, which have largely been funded prior to December 31, 2004, such as Baobab, Primrose and West Espoir provide identified growth in production volumes in 2005 and 2006, and will generate incremental free cash flows during the period 2005 to 2008 with which to finance the Horizon Project. In January 2005, the Board of Directors of the Company authorized an expanded hedging program for the Company in an effort to reduce the risk of volatility in commodity price markets and to underpin the Company's cash flow through the Horizon Project construction period. This expanded program allows for up to 75% of the near 12 months estimated production, up to 50% of the following 13 to 24 months estimated production and up to 25% of production expected in months 25 to 48 to be hedged. This revised hedging program allows the Company to have greater stability in its free cash flow and enhances the Company's financial flexibility during the Horizon Project construction years. The Company currently has collar hedges covering approximately 71% and 45% of estimated 2005 and 2006 crude oil production respectively. Similarly, approximately 67% and 35% of estimated 2005 and 2006 natural gas production has been hedged. The Company may also look to offload capital commitments through the acceptance of complementary business partners, or potentially, project joint venture partners. 55 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Long-term debt Long-term debt at December 31, 2004, increased $790 million from the prior year. The debt to EBITDA ratio increased to 0.9x and the debt to book capitalization increased to 33.8% compared to a debt to EBITDA ratio of 0.8x and a debt to book capitalization of 32.8% in 2003. 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, 2004, the Company had: o $2.8 billion of available unused bank credit facilities; o A fixed / floating interest rate mix of 43% / 57%; o 77% of borrowings denominated in US dollars; and o 85% of total long-term debt as non-bank based borrowing with a weighted average maturity of 16 years. In December 2004, the Company issued US$350 million of debt securities maturing December 2014, bearing interest at 4.90% and US$350 million of debt securities maturing February 2035, bearing interest at 5.85%. Proceeds from the securities issued were used to repay bankers' acceptances under the Company's bank credit facilities. The Company has entered into certain interest rate swap contracts to convert the fixed rate interest coupon into a floating interest rate on the securities due December 2014. The Company filed a short form prospectus in May 2003 that allows for the issue of up to US$2 billion of debt securities in the United States until June 2005. Currently the Company has US$1.3 billion remaining under the $2 billion shelf prospectus. 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. As at December 31, 2004, the Company had unsecured bank credit facilities of $3,425 million compared to $1,925 million at the close of 2003 (2002 - $2,275 million). In December 2004, the Company executed a $1,500 million, 5-year revolving credit facility, with three, one-year extension options. 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. Share capital Shareholders of the Company approved a subdivision or share split of its issued and outstanding common shares on a two-for-one basis at the Company's Annual and Special Meeting held on May 6, 2004. The Company is authorized to issue an unlimited number of common shares. As at December 31, 2004, there were 268,181,000 common shares outstanding. As at February 18, 2005 there were 268,221,000 common shares outstanding. In addition, the Company is authorized to issue 200,000 Class 1 preferred shares. There were no preferred shares outstanding during these periods. During 2004, the Company issued 1,591,000 common shares from the exercise of stock options for proceeds of $24 million. During 2003, the Company issued 5,381,000 common shares from the exercise of stock options for proceeds of $89 million. In 2002, the Company issued 20 million common shares at an attributed value of $522 million as part of the consideration to acquire Rio Alto. A further 5,046,000 common shares were issued from the exercise of stock options throughout 2002 for proceeds of $82 million. In January 2005, the Company renewed its Normal Course Issuer Bid allowing it to purchase up to 13,409,006 common shares or 5% of the Company's outstanding common shares on the date of announcement, during the 12-month period beginning January 24, 2005 and ending January 23, 2006. As at December 31, 2004, the Company had purchased 873,400 common shares for a total cost of $33 million at an average purchase price of $38.01 per common share pursuant to a Normal Course Issuer Bid that has been in place since January 24, 2004. 56 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The Company declared dividends on common shares in the amount of $107 million or $0.40 per common share in 2004, up from $81 million or $0.30 per common share in 2003 (2002 - $64 million, $0.25 per common share). In February 2005, the Company's Board of Directors approved an increase in the annual dividend paid by the Company to $0.45 per common share for 2005. The 12.5% increase recognizes the stability of the Company's cash flow and provides a return to Shareholders. This is the fifth consecutive year in which the Company has paid dividends and the fourth consecutive year of an increase in the distribution paid to its Shareholders. In February 2004, the Company's Board of Directors approved an increase in the annual dividend paid by the Company to $0.40 per common share in 2004, up from the previous level of $0.30 per common share. Commitments and off balance sheet arrangements In the normal course of business, the Company has entered into various contractual arrangements and commitments that will have an impact on the Company's future operations. These contractual obligations and commitments relate primarily to debt repayments, operating leases relating to office space and offshore production and storage vessels, firm commitments for gathering, processing and transmission services. The following table summarizes the Company's commitments as at December 31, 2004:
($ millions) 2005 2006 2007 2008 2009 Thereafter - ------------ ------ ------ ------ ------ ------ ---------- Natural gas transportation $ 194 $ 147 $ 100 $ 78 $ 37 $ 168 Crude oil transportation and pipeline $ 11 $ 9 $ 11 $ 12 $ 13 $ 154 Offshore equipment operating lease $ 110 $ 48 $ 48 $ 48 $ 48 $ 184 Baobab Project $ 99 $ - $ - $ - $ - $ - Offshore drilling and other $ 125 $ 8 $ - $ - $ - $ - Electricity $ 26 $ 28 $ 20 $ 13 $ 8 $ 34 Office lease $ 21 $ 21 $ 22 $ 23 $ 24 $ 30 Processing $ 5 $ 2 $ - $ - $ - $ - Horizon Project $ 99 $ - $ - $ - $ - $ - Long-term debt $ 194 $ - $ 162 $ 37 $ 69 $2,713
Subsequent event On February 9, 2005, the Company's Board of Directors unanimously authorized the Company to proceed with Phase 1 of the Horizon Oil Sands Project. The Horizon Project is designed as a phased development and includes two components: the mining of bitumen and an onsite upgrader. Phase 1 production is targeted to begin at 110,000 bbl/d of 34 degree API light sweet, synthetic crude oil ("SCO"). Phase 2 would increase production to 155,000 bbl/d of SCO. Phase 3 would further increase production to 232,000 bbl/d of SCO. Total expected capital costs for all three phases of development are estimated at $10.8 billion. Capital costs for the first phase of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million, with $1.4 billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2 billion to be incurred in 2006, 2007 and 2008, respectively. Oil and natural gas reserves Canadian Natural retains qualified independent reserve evaluators, Sproule Associates Limited ("Sproule"), and Ryder Scott Company ("Ryder Scott"), to evaluate 100% of the Company's proved and probable oil and natural gas reserves and prepare Evaluation Reports on the Company's total reserves. Sproule evaluated the North American assets and Ryder Scott evaluated the international assets and a portion of the North American assets. Canadian Natural has been granted an exemption from the 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 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. Canadian Natural 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; however, 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. Canadian Natural has significant oil reserves that are considered heavy with a gravity of less than 20 degrees. Heavy crude oil sells at a discount to light crude oil using the benchmark West Texas Intermediate, which has an API gravity of approximately 40 degrees, because it requires upgrading before it can be processed by conventional refineries. There is a finite capacity for upgrading in North America, which is often reached when heavy crude oil from other countries enters the North American market. Heavy crude oil requires blending with condensate or light synthetic crude oil ("diluent") in order for it to be transported in a pipeline. During the winter, heavy crude oil requires a higher proportion of diluent because of the cold temperatures. Heavy crude oil is also processed into asphalt, which is typically in demand during the spring to fall paving months. As a result of these factors, prices for heavy crude oil are historically low in December. Exacerbating this trend was reduced demand for heavy crude oil due to refinery turnarounds and other operational issues. During 2004 the price of heavy crude oil averaged US$30.40 per barrel but on December 31, 2004, the date the Company's oil and natural gas reserves were evaluated, the calculated price of Hardisty 12 degree API heavy crude oil was less. As a result, 30 mmbbl of net proved heavy crude oil reserves did not produce positive cash flow and, in accordance with SEC regulations, were debooked. Notwithstanding the economics at December 31, 2004, the current price of heavy crude oil has returned to a price sufficient to return the reserves subtracted by negative revision to the proved reserve category. 57 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Horizon oil sands mining reserves are not part of Canadian Natural's year-end reserves disclosure. Horizon reserves were evaluated as at February 9, 2005. Gilbert Laustsen Jung Associates Ltd. ("GLJ"), an independent qualified reserves evaluator, was retained by the Reserves Committee of Canadian Natural's Board of Directors to evaluate reserves associated with the Horizon Project incorporating both the mining and upgrading projects. These reserves were evaluated under SEC Industry Guide 7. The Board of Directors of the Company has a Reserves Committee, which has met with and carried out independent due diligence procedures with each of Sproule, Ryder Scott and GLJ 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. 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 12 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. 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. 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 the Company's 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 the majority of 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; 58 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS 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 2004, the Company's capital expenditures included $32 million for abandonment expenditures, down from $40 million in 2003 (2002 - $43 million). Estimated future site restoration liability
($ millions) 2004 2003 - ------------ ------- ------- North America $ 1,776 $ 1,491 North Sea 1,263 764 Offshore West Africa 24 26 ------- ------- 3,063 2,281 North Sea PRT recovery (601) (331) ------- ------- $ 2,462 $ 1,950 ======= =======
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 $601 million (2003 - $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 $2,462 million (2003 - $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. 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. 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 continued 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. Critical accounting estimates The preparation of financial statements requires Management 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. Actual results could differ from those estimates. 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 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. The carrying amount of oil and natural gas properties in each cost centre may not exceed their recoverable amount ("the ceiling test"). The recoverable amount is calculated as the undiscounted cash flow using proved reserves and estimated future prices and costs. If the carrying amount of a cost centre exceeds its recoverable amount, then an impairment loss equal to the amount by which the carrying amount of the properties exceeds their fair value is charged against net earnings. Fair value is calculated as the cash flow from those properties using proved and probable reserves and expected future prices and costs, discounted at a risk-free interest rate. 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. 59 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Oil and natural gas reserves The Company retains qualified independent reserves evaluators to evaluate the Company's proved and probable oil and natural gas reserves. In 2004, 100% of the Company's reserves were evaluated by qualified independent reserves evaluators. 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 carrying amounts under the ceiling test. Asset retirement obligation The fair value of asset retirement obligations related to long-term assets are recognized as a liability in the period in which they are incurred. Retirement costs equal to the fair value of the asset retirement obligations are capitalized as part of the cost of associated capital assets and are are amortized to expense through depletion over the life of the asset. The fair value of the asset retirement obligation is estimated by discounting the expected future cash flows to settle the asset retirement obligation at the Company's credit-adjusted risk-free interest rate. In subsequent periods, the asset retirement obligation is adjusted for the passage of time and for any changes in the amount or timing of the underlying future cash flows. Differences between actual and estimated costs to settle the asset retirement obligation, timing of cash flows to settle the obligation and future inflation rates could result in gains or losses on the settlement of the asset retirement obligations. Risk management activities Financial instruments that do not qualify as hedges under Accounting Guideline 13 or are not designated as hedges are recorded at fair value on the Company's consolidated balance sheet, with subsequent changes in fair value recognized in net earnings. The Company utilizes various financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are not used for trading purposes. The Company enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to protect cash flow for capital expenditure programs. The Company also enters into foreign currency denominated financial instruments to manage future US dollar denominated crude oil and natural gas sales. Gains or losses on these contracts are included in risk management activities. 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 contracts require the periodic exchange of payments without the exchange of the notional principle amount on which the payments are based. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. Gains or losses on interest rate contracts not designated as hedges are included in risk management activities. The Company enters into cross currency swap agreements to manage its currency exposure on long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense. Gains or 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 amortized into 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. Purchase price allocations The costs of corporate and asset acquisitions are allocated to the acquired assets and liabilities based on their fair value at the time of acquisition. The determination of fair value requires Management to make assumptions and estimates regarding future events. The allocation process is inherently subjective and impacts the amount assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts the Company's reported assets and liabilities and future net earnings due to the impact on future DD&A expense and impairment tests. Production sharing contractual arrangements The Company's operations outside of North America and the North Sea are governed by production sharing contracts ("PSC"). Under the PSC, the Company and its working interest partners typically bear all the risks and costs for exploration, development and production. In exchange, if exploration is successful, the Company is given the opportunity to recover its investment and production expenses from the sale of crude oil and natural gas production ("cost oil"). The Company is also entitled to a share of the excess of what is required to recover the Company's investment and production expenses ("profit oil"), the allocation of which varies from contract to contract. Together the cost oil and profit oil represent the Company's entitlement. The Company records production, sales and reserves based on its working interest ownership. The PSC stipulates that income taxes are to be paid out of the respective national oil company share of production. The difference between the Company's working interest ownership and its annual entitlement is accounted for either a royalty expense or current income tax expense in accordance with the PSC. 60 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS New accounting standards Full cost accounting Effective January 1, 2004, the Company prospectively adopted the CICA's 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 their recoverable amount calculated as 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 fair value of the assets, calculated as the present value of expected cash flows using proved and probable reserves and expected future prices and costs. The adoption of this standard had no effect on the Company's consolidated financial statements for the year ended December 31, 2004. Asset retirement obligations Effective January 1, 2004, the Company retroactively adopted the CICA's Section 3110, "Asset Retirement Obligations". The Section requires the recognition of a liability for the fair value of the asset retirement obligation related to long-term assets. Retirement costs equal to the fair value of the asset 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 asset retirement obligation is adjusted for the passage of time and for any changes in the amount or timing of the underlying future cash flows. This new standard was adopted retroactively and prior period comparative balances have been restated. Adoption of the standard had the following effects on the Company's consolidated balance sheet as at December 31, 2003:
($ millions) December 31, 2003 - ------------ ----------------- Consolidated balance sheet Increase property, plant and equipment $ 445 Decrease future site restoration liability $ (447) Increase asset retirement obligation $ 897 Increase future income tax liability $ 3 Decrease foreign currency translation adjustment $ (14) Increase retained earnings $ 6
Adoption of the standard had the following effects on the Company's consolidated statements of earnings and retained earnings:
Year Ended ($ millions) 2004 2003 2002 - ------------ ------ ------ ------ Increase opening retained earnings $ 6 $ 10 $ 41 Decrease depletion, depreciation and amortization $ (120) $ (56) $ (16) Increase asset retirement obligation accretion $ 51 $ 62 $ 68 Increase (decrease) future income tax expense $ 28 $ (2) $ (21)
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. Risk management activities On January 1, 2004, the Company prospectively adopted the CICA's Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments". Guideline 13 and EIC 128 require that financial instruments that are not designated as hedges be recorded on the Company's consolidated balance sheet at fair value on the date thereof, with subsequent changes in fair value recorded in earnings on a quarterly reporting basis. Adoption of Guideline 13 and EIC 128 resulted in the Company recognizing an unrealized mark-to-market gain of $40 million ($27 million, net of tax) for the year ended December 31, 2004 relating to its financial instruments. The unrealized gain assumes that all unsettled derivative financial instruments were settled on December 31, 2004 and were valued based on market conditions existing at that point in time. As a result of the adoption of this standard, the Company expects the volatility in its net earnings to increase, which is directly attributable to the corresponding volatility in crude oil and natural gas prices and the unsettled derivative financial instruments. The Guideline had the following effects on the Company's consolidated financial statements:
($ millions) January 1, 2004 - ------------ --------------- Consolidated balance sheet Increase derivative financial instruments asset $ 40 Increase deferred revenue $ 40
61 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Preferred Securities Effective December 31, 2004, the Company early adopted changes to the CICA's Section 3860, "Financial Instruments - Presentation and Disclosure" that relate to contractual obligations that may be settled by delivery of the Company's common shares. Under the new rules, these obligations must be classified as liabilities on the Company's consolidated balance sheets. Previously, these obligations were classified as equity. These changes have been adopted retroactively and prior periods have been restated. Adoption of the changes had the following effects on the Company's consolidated financial statements:
($ millions) 2004 2003 2002 - ------------ ------ ------ ------ Increase long-term debt $ 96 $ 103 $ 126 Decrease preferred securities $ (96) $ (103) $ (126) Increase interest expense $ 9 $ 9 $ 10 Increase foreign exchange gain $ 7 $ 23 $ 1 (Decrease) increase future income tax expense $ (1) $ 1 $ (4) Decrease dividend on preferred securities, net of tax $ (5) $ (5) $ (6) Decrease revaluation of preferred securities, net of tax $ (4) $ (18) $ (1)
Impairment of long-lived assets Effective January 1, 2004, the Company prospectively adopted the CICA's Section 3063 "Impairment of Long-lived Assets". The Section establishes standards for the recognition, measurement and disclosure of the impairment of long-lived assets. The Section addresses when impairment should be recognized and how to measure the amount of impairment. An impairment loss is recognized when the carrying amount of a long-lived asset exceeds its fair value calculated as the sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is measured as the amount by which the long-lived assets' carrying amount exceeds its fair value. Adoption of the Section had no effect on the Company's consolidated financial statements for the year ended December 31, 2004. Variable interest entities ("VIE's") Effective January 1, 2004, the Company retroactively adopted the CICA's Accounting Guideline 15, "Consolidation of Variable Interest Entities" without restating prior periods. The Guideline requires the Company to identify VIE's in which they have an interest, determine whether they are the primary beneficiary of such entities and, if so, consolidate them. The primary beneficiary is the enterprise that will absorb or receive the majority of the VIE's expected losses, expected residual returns, or both. A VIE is an entity where (1) its equity investment at risk is insufficient to permit the entity to finance its activities without additional subordinated support from others, (2) the equity investors lack either voting control, an obligation to absorb expected losses or the right to receive expected residual returns, and (3) it does not meet specified exemption criteria. The adoption of this Guideline had no impact on the Company's consolidated financial statements. Financial instruments In January 2005, the CICA issued Section 3855 "Financial Instruments - Recognition and Measurement". This Section prescribes when a financial asset, financial liability, or non-financial derivative is to be recognized on the balance sheet and at what amount - sometimes using fair value; other times using cost-based measures. This Section also specifies how financial instruments gains and losses are to be presented. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Transitional provisions for this Section are complex and vary based on the type of financial instruments under consideration. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Hedges In January 2005, the CICA issued Section 3865 "Hedges". This Section expands on existing Accounting Guideline 13, "Hedging Relationships", and Section 1650 "Foreign Currency Translation", by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Retroactive application of this Section is not permitted. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Comprehensive Income In January 2005, the CICA issued Section 1530 "Comprehensive Income". This Section introduces new standards for reporting and display of comprehensive income. Comprehensive income is the change in equity (net assets) of a company during a reporting period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Financial statements of prior periods are required to be restated for certain comprehensive income items. In addition, a company is encouraged, but not required to present reclassification adjustments, in comparative financial statements provided for earlier periods. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. 62 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS Equity In January 2005, the CICA issued Section 3251 "Equity". This Section replaces Section 3250 "Surplus". It establishes standards for the presentation of equity and changes in equity during a reporting period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Financial statements of prior periods are required to be restated for certain specified adjustments. For all other items, comparative financial statements are presented are not restated, but an adjustment to the opening balance of accumulated other comprehensive income may be required. In addition, a company is encouraged, but not required to present reclassification adjustments, in comparative financial statements provided for earlier periods. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. 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 2005 to average 1,448 to 1,510 mmcf/d of natural gas and 307,000 to 335,000 bbl/d of crude oil and NGLs. First quarter 2005 production guidance for natural gas is 1,400 to 1,482 mmcf/d of natural gas and 269,000 to 290,000 bbl/d of crude oil and NGLs. The budgeted capital expenditures in 2005 are currently expected to be as follows:
($ millions) 2005 Budget - ------------ ----------- North America natural gas $ 1,350 North America crude oil and NGLs 910 North Sea crude oil and NGLs 420 Offshore West Africa crude oil and NGLs 400 Property acquisitions and midstream 50 ------- 3,130 Horizon Oil Sands Project 1,372 ------- Total $ 4,502 =======
North America natural gas In 2005, the Company expects to drill approximately 1,033 net natural gas wells, 690 net crude oil wells and 199 stratigraphic test/service wells. The 2005 North American natural gas program will be highlighted by expanded drilling programs in the Northwest Alberta and Northeast British Columbia core regions as shown below:
(number of wells) 2005 Budget - ----------------- ----------- Northeast British Columbia 240 Northwest Alberta 194 Northern Plains 205 Southern Plains 394 ----- Total 1,033 =====
Drilling in 2005 reflects higher activity levels targeting the shallow Notikewin zone in Northeast British Columbia as well as increased Cardium drilling in Northwest Alberta. Drilling of shallow gas and coal bed methane wells will increase in the Southern Plains core region. Conventional drilling will also increase in the Northern Plains core region. During 2005, approximately 90 wells targeting deep natural gas are budgeted, including nine in the Foothills area. The Foothills area drilling increases reflect both increased focus on the area as well as new drilling targets identified on assets acquired during the first half of 2004. 63 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT North America crude oil and NGLs The 2005 drilling program consists of:
(number of wells) 2005 Budget - ----------------- ----------- Conventional heavy crude oil 398 Thermal heavy crude oil 105 Light crude oil 101 Pelican Lake crude oil 67 ----- Total 671 =====
The 2005 drilling program consists of 398 conventional heavy crude oil wells, 105 thermal heavy crude oil wells, 101 light crude oil wells and 67 Pelican Lake crude oil wells. The Company continues the disciplined development of its heavy crude oil resources. Conventional heavy crude oil drilling will increase, reflecting favourable crude oil prices as well as new opportunities identified in the property acquisitions made during 2004. Due to the nature of heavy crude oil production patterns, where production volumes ramp up during the first months of production, much of the production resulting from the expanded drill program will not be realized until late 2005. In 2005, the Company expects to continue its Primrose thermal crude oil expansion plans. The two new phases that commenced production in mid 2004 significantly enhance the economics of this project and are a positive indicator for future pads that will be drilled. Production from this project is subject to the cycling of steam injection and crude oil production and is expected to remain at similar levels to the 2004 production. The Pelican Lake waterflood test program continues and will be expanded to additional lands in the area. The Company will also be piloting the use of polymer flood on a portion of the field in an effort to further enhance field recoveries. As a result of the above activities, North America 2005 crude oil and NGLs production is expected to increase slightly from 2004 levels. Based upon the capital expenditure budget, the Company expects to incur Canadian current income tax expense in 2005 of $200 to $300 million. The Horizon Oil Sands Project The Horizon Project is designed as a phased development and includes two components: the mining of bitumen and an onsite upgrader. Phase 1 production is planned to begin at 110,000 bbl/d of 34 degree API light, sweet synthetic crude oil ("SCO"). Phase 2 will increase production to 155,000 bbl/d of SCO. Phase 3 will further increase production to 232,000 bbl/d of SCO. The phased approach provides the Company with improved cost and project controls including labour and materials management, and directionally mitigates the effects of growth on local infrastructure. Total expected capital costs for all three phases of the development are estimated at $10.8 billion. Capital costs for Phase 1 of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million with $1.4 billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2 billion to be incurred in 2006, 2007 and 2008, respectively. Extensive front end design and the high degree of project definition have enabled the Company to obtain approximately 68% of Phase 1 costs on a fixed price basis. The high degree of up front project engineering and pre-planning will also reduce the risks associated with scope changes. On February, 9, 2005, the Board of Directors unanimously authorized management to proceed with Phase 1 of the Horizon Project. North Sea The capital budget in 2005 for the North Sea is $420 million and includes the drilling of approximately 12 net platform wells while continuing the successful workover and recompletion program. The Company will also conduct a mobile drilling program in which four subsea wells will be drilled at Nadia, Thelma (two) and Columba E. These wells, with the exception of Nadia, are step-out development wells on existing proved properties. The Nadia well is an exploration of new terraces in the Ninian/Columba area. Average crude oil production is expected to increase from 2004 production levels; however, natural gas volumes will be lower as natural gas sales at the Banff Field are diverted to reinjection. Offshore West Africa In 2005, the capital budget for Offshore West Africa is set at $400 million, of which the Company anticipates $210 million to be spent on finalizing the development of the Baobab Field in Cote d'Ivoire and $100 million to be spent developing the West Espoir Field. The remainder will be spent on various exploration activities. At East Espoir, an additional four wells are scheduled for drilling in early 2005 as a result of additional testing and evaluation that revealed a larger quantity of crude oil in place, based upon reservoir studies and production history to date. These new producer wells will effectively exploit this additional potential and could increase the recoverable resources from the field. Average production is expected to increase as a result of the commissioning of the Baobab Field in mid 2005 as well as a result of the drilling of additional producer wells in East Espoir. Sensitivity analysis The following table is indicative of the annualized sensitivities of cash flow and net earnings from changes in certain key variables. The analysis is based on business conditions and production volumes during the fourth quarter of 2004. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. 64 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS
Cash flow from Cash flow from operations operations Net earnings Net earnings ($ millions) ($/share, basic) ($ millions) ($/share, basic) ------------ ---------------- ------------ ---------------- Price changes Crude oil - WTI US$1.00/bbl (1) Excluding financial derivatives $ 96 $ 0.36 $ 68 $ 0.25 Including financial derivatives $ 80 $ 0.30 $ 43 $ 0.16 Natural gas - AECO C$0.10/mcf (1) Excluding financial derivatives $ 37 $ 0.14 $ 24 $ 0.09 Including financial derivatives $ 33 $ 0.12 $ 21 $ 0.08 Volume changes Crude oil - 10,000 bbl/d $ 73 $ 0.27 $ 34 $ 0.13 Natural gas - 10 mmcf/d $ 18 $ 0.07 $ 7 $ 0.03 Foreign currency rate change $0.01 change in C$ in relation to US$ (1) Excluding financial derivatives $ 56 $ 0.21 $ 12 $ 0.05 Including financial derivatives $ 55 - 58 $0.21 - 0.22 $ 12 - 13 $0.04 - 0.05 Interest rate change - 1% $ 13 $ 0.05 $ 13 $ 0.05
- ------------ (1) For details of financial instruments in place, see consolidated financial statements note 12. Daily production by segment, before royalties
Q1 Q2 Q3 Q4 2004 2003 2002 ------- ------- ------- ------- ------- ------- ------- Crude oil and NGLs (bbl/d) North America 192,151 203,741 214,336 214,493 206,225 174,895 169,675 North Sea 57,099 60,105 71,517 69,971 64,706 56,869 38,876 Offshore West Africa 12,036 11,552 11,409 11,240 11,558 10,628 6,784 ------- ------- ------- ------- ------- ------- ------- Total 261,286 275,398 297,262 295,704 282,489 242,392 215,335 ======= ======= ======= ======= ======= ======= ======= Natural gas (mmcf/d) North America 1,230 1,389 1,336 1,365 1,330 1,245 1,204 North Sea 54 55 53 40 50 46 27 Offshore West Africa 10 8 7 5 8 8 1 ------- ------- ------- ------- ------- ------- ------- Total 1,294 1,452 1,396 1,410 1,388 1,299 1,232 ======= ======= ======= ======= ======= ======= ======= Barrels of oil equivalent (boe/d) North America 397,194 435,238 436,986 442,072 427,936 382,315 370,337 North Sea 66,127 69,175 80,393 76,560 73,093 64,469 43,391 Offshore West Africa 13,623 12,930 12,567 12,113 12,806 12,030 6,994 ------- ------- ------- ------- ------- ------- ------- Total 476,944 517,343 529,946 530,745 513,835 458,814 420,722 ======= ======= ======= ======= ======= ======= =======
Per unit results
Q1 Q2 Q3 Q4 2004 2003 2002 ------- ------- ------- ------- ------- ------- ------- Crude oil and NGLs ($/bbl) Sales price (1) $ 34.21 $ 36.72 $ 43.50 $ 36.92 $ 37.99 $ 32.66 $ 31.22 Royalties 2.91 3.15 3.59 2.95 3.16 2.77 3.16 Production expense 9.58 9.92 10.21 10.41 10.05 10.28 8.45 ------- ------- ------- ------- ------- ------- ------- Netback $ 21.72 $ 23.65 $ 29.70 $ 23.56 $ 24.78 $ 19.61 $ 19.61 ======= ======= ======= ======= ======= ======= ======= Natural gas ($/mcf) Sales price (1) $ 6.31 $ 6.64 $ 6.24 $ 6.77 $ 6.50 $ 6.21 $ 3.77 Royalties 1.27 1.38 1.39 1.34 1.35 1.32 0.78 Production expense 0.65 0.66 0.71 0.68 0.67 0.60 0.57 ------- ------- ------- ------- ------- ------- ------- Netback $ 4.39 $ 4.60 $ 4.14 $ 4.75 $ 4.48 $ 4.29 $ 2.42 ======= ======= ======= ======= ======= ======= ======= Barrels of oil equivalent ($/boe) Sales price (1) $ 35.88 $ 38.20 $ 40.92 $ 38.51 $ 38.45 $ 34.84 $ 27.02 Royalties 5.03 5.55 5.68 5.21 5.37 5.20 3.91 Production expense 7.02 7.12 7.59 7.61 7.35 7.15 5.99 ------- ------- ------- ------- ------- ------- ------- Netback $ 23.83 $ 25.53 $ 27.65 $ 25.69 $ 25.73 $ 22.49 $ 17.12 ======= ======= ======= ======= ======= ======= =======
- ------------ (1) Including transportation costs and excluding risk management activities. 65 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Netback analysis
($/boe, except daily production) 2004 2003 2002 -------- -------- -------- Daily production, before royalties (boe/d) 513,835 458,814 420,722 Sales price (1) $ 38.45 $ 34.84 $ 27.02 Royalties 5.37 5.20 3.91 Production expense 7.35 7.15 5.99 -------- -------- -------- Netback 25.73 22.49 17.12 Midstream contribution (0.26) (0.28) (0.25) Administration 0.61 0.52 0.40 Share bonus plan 0.05 - - Interest 1.01 1.20 1.26 Realized risk management activities loss 2.52 1.09 0.54 Realized foreign exchange loss 0.02 0.05 0.02 Taxes other than income tax - current 1.12 0.69 0.35 Current income tax - North America 0.47 0.14 - Current income tax - Large Corporations Tax 0.05 0.06 0.14 Current income tax - North Sea 0.01 0.26 (0.13) Current income tax - Offshore West Africa 0.07 0.09 0.04 Current income tax - other 0.01 - - -------- -------- -------- Cash flow $ 20.05 $ 18.67 $ 14.75 ======== ======== ========
- ------------ (1) Including transportation costs and excluding risk management activities. Quarterly financial information
($ millions, except per share amounts) Q1 Q2 Q3 Q4 Total ------- ------- ------- ------- ------- 2004 Revenue $ 1,638 $ 1,865 $ 2,075 $ 1,969 $ 7,547 Net earnings $ 258 $ 259 $ 311 $ 577 $ 1,405 Per common share - basic $ 0.96 $ 0.97 $ 1.16 $ 2.15 $ 5.24 - diluted $ 0.96 $ 0.97 $ 1.13 $ 2.13 $ 5.20 Cash flow from operations $ 848 $ 930 $ 1,041 $ 950 $ 3,769 Per common share - basic $ 3.16 $ 3.47 $ 3.88 $ 3.54 $ 14.06 - diluted $ 3.14 $ 3.47 $ 3.85 $ 3.52 $ 13.98 2003 $ 1,840 $ 1,502 $ 1,454 $ 1,359 $ 6,155 Net earnings (1) $ 427 $ 525 $ 201 $ 250 $ 1,403 Per common share - basic (1)(2) $ 1.60 $ 1.96 $ 0.75 $ 0.93 $ 5.23 - diluted (1)(2) $ 1.52 $ 1.89 $ 0.74 $ 0.91 $ 5.06 Cash flow from operations $ 906 $ 762 $ 758 $ 734 $ 3,160 Per common share - basic (2) $ 3.38 $ 2.84 $ 2.81 $ 2.74 $ 11.77 - diluted (2) $ 3.27 $ 2.79 $ 2.78 $ 2.71 $ 11.53
- ------------ (1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) Restated to reflect two-for-one share split in May 2004. 66 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The following discussion highlights some of the more significant factors that impacted the net earnings in the eight most recently completed quarters. In the first quarter of 2004, the Company acquired certain resource properties, collectively known as Petrovera, in its Northern Plains core region. In the second quarter of 2004, the Company completed the acquisition of certain resource properties located in Northeast British Columbia and Northwest Alberta. These properties include further ownership in the Ladyfern natural gas field. In the third quarter of 2004, the Company acquired certain light crude oil producing properties in the Central North Sea. The acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields). In the fourth quarter of 2004, the Company completed the acquisition of certain resource properties located in Alberta, British Columbia and Saskatchewan. The acquisition extends the Company's Northern Plains core region into the light crude oil operating area of Dawson. The Company issued US$350 million of debt securities maturing 2014, bearing interest at 4.90% and US$350 million of debt securities maturing 2035, bearing interest at 5.85%. In the second quarter of 2003, the Canadian Government introduced several income tax changes, including rate reductions, for the resource industry. In addition, the Province of Alberta reduced corporate income tax rates. As a result of these changes, the future income tax liability was decreased by $247 million. Also, in the second quarter of 2003, the Company modified its employee stock option plan to provide for a cash payment option. A charge of $72 million after taxes ($105 million before taxes) was recognized to represent the mark-to-market liability of the plan for all earned options as at June 30, 2003. Trading and share statistics
2004 2003 Q1 Q2 Q3 Q4 Total Total --------- --------- --------- --------- -------- --------- TSX-C$ Trading volume (thousands) 69,449 80,934 65,017 87,612 303,012 295,351 Share price ($/share) High $ 38.25 $ 40.85 $ 51.04 $ 55.15 $ 55.15 $ 33.61 Low $ 31.91 $ 35.08 $ 39.75 $ 45.80 $ 31.91 $ 22.60 Close $ 36.35 $ 40.05 $ 50.50 $ 51.25 $ 51.25 $ 32.69 Market capitalization at December 31 ($ millions) $ 13,744 $ 8,742 Shares outstanding (thousands) 268,181 267,463 - ----------------------------------------------------------------------------------------------------------------- NYSE - US$ Trading volume (thousands) 11,775 16,418 13,255 21,286 62,734 23,458 Share price ($/share) High $ 28.94 $ 30.54 $ 40.31 $ 44.74 $ 44.74 $ 25.70 Low $ 23.88 $ 25.88 $ 29.72 $ 37.12 $ 23.88 $ 14.63 Close $ 27.82 $ 29.90 $ 39.83 $ 42.77 $ 42.77 $ 25.22 Market capitalization at December 31 ($ millions) $ 11,470 $ 6,745 Shares outstanding (thousands) 268,181 267,463
67 CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL 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 which 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, Vice President, Financial Finance Accounting & Controls February 18, 2005 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, 2004 and 2003 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2004. 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated 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, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles. /s/ PricewaterhouseCoopers LLP - --------------------------------- Chartered Accountants Calgary, Alberta, Canada February 18, 2005 Comments by Auditor for U.S. readers on Canada-U.S. Reporting Differences In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company's consolidated financial statements, such as the change described in Note 2 to the consolidated financial statements. Our report to the shareholders dated February 18, 2005 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors' report when the change is properly accounted for and adequately disclosed in the consolidated financial statements. /s/ PricewaterhouseCoopers LLP - --------------------------------- Chartered Accountants Calgary, Alberta, Canada February 18, 2005 68 EX-99 5 ex-4form40f_2004.txt EXHIBIT 4 EXHIBIT 4 --------- SUPPLEMENTARY OIL & GAS INFORMATION 2004 ANNUAL REPORT 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 qualified independent reserves evaluators to evaluate the Company's proved oil and natural gas reserves. o For the year ended December 31, 2004, the reports by Sproule Associates Limited ("Sproule") and Ryder Scott Company covered 100% of the Company's reserves; o For the year ended December 31, 2003, the reports by Sproule covered 100% of the Company's reserves; and o For the year ended December 31, 2002, the reports by Sproule covered 89% 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, 2004, 2003 and 2002:
Offshore Oil and natural gas liquids (mmbbl) North America North Sea West Africa Total - ----------------------------------- ------------- --------- ----------- ----- Net proved reserves 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 Extensions and discoveries 41 35 - 76 Improved recovery 1 10 - 11 Purchases of reserves in place 36 38 - 74 Sales of reserves in place - - - - Production (66) (24) (4) (94) Revisions of previous estimates 48 22 34 104 ----- ----- ----- ----- Reserves, December 31, 2004 648 303 115 1,066 ===== ===== ===== ===== Net proved developed reserves: December 31, 2001 344 51 20 415 December 31, 2002 340 107 27 474 December 31, 2003 348 138 23 509 December 31, 2004 367 218 20 605 ----- ----- ----- -----
91 SUPPLEMENTARY OIL & GAS INFORMATION 2004 ANNUAL REPORT
Offshore NATURAL GAS (bcf) North America North Sea West Africa Total - ----------------- ------------- --------- ----------- ----- Net proved reserves 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) Revisions 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 Extensions and discoveries 408 -- -- 408 Improved recovery 6 -- -- 6 Purchases of reserves in place 182 10 -- 192 Sales of reserves in place (8) -- -- (8) Production (383) (18) (3) (404) Revision of previous estimates (40) (27) 11 (56) ------ ------ ------ ------ RESERVES, DECEMBER 31, 2004 2,591 27 72 2,690 ====== ====== ====== ====== Net proved developed reserves: 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 DECEMBER 31, 2004 2,213 12 5 2,230 ====== ====== ====== ======
CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS ACTIVITIES
2004 ------------------------------------------------------------ OFFSHORE (millions of Canadian dollars) NORTH AMERICA NORTH SEA WEST AFRICA TOTAL - ------------------------------ ------------- --------- ----------- ----- Proved properties $ 18,749 $ 2,518 $ 565 $ 21,832 Unproved properties 1,028 44 536 1,608 19,777 2,562 1,101 23,440 Less: accumulated depletion and depreciation (6,410) (739) (192) (7,341) -------- -------- -------- -------- Net capitalized costs $ 13,367 $ 1,823 $ 909 $ 16,099 ======== ======== ======== ========
2003 ----------------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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 ----------------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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 ======== ======== ======== ========
92 SUPPLEMENTARY OIL & GAS INFORMATION 2004 ANNUAL REPORT COSTS INCURRED IN OIL AND NATURAL GAS ACTIVITIES
2004 -------------------------------------------------------- OFFSHORE (millions of Canadian dollars) NORTH AMERICA NORTH SEA WEST AFRICA TOTAL - ------------------------------ ------------- --------- ----------- ----- Property acquisitions Proved $ 1,748 $ 302 $ -- $ 2,050 Unproved 298 4 -- 302 Exploration 290 11 37 338 Development 1,403 308 259 1,970 ------- ------- ------- ------- Finding and development costs 3,739 625 296 4,660 Asset retirement costs 98 165 (10) 253 Actual retirement expenditures (32) -- -- (32) ------- ------- ------- ------- Costs incurred $ 3,805 $ 790 $ 286 $ 4,881 ======= ======= ======= =======
2003 --------------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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 ---------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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 ====== ====== ====== ======
93 SUPPLEMENTARY OIL & GAS INFORMATION 2004 ANNUAL REPORT 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, 2004, 2003 and 2002 are summarized in the following tables:
2004 ------------------------------------------------- OFFSHORE (millions of Canadian dollars) NORTH AMERICA NORTH SEA WEST AFRICA TOTAL - ------------------------------ ------------- --------- ----------- ----- Oil and natural gas revenue, net of royalties $ 4,579 $ 1,203 $ 216 $ 5,998 Production (976) (370) (36) (1,382) Transportation (256) (32) - (288) Depletion, depreciation and amortization (1,438) (265) (53) (1,756) Asset retirement obligation accretion (28) (22) (1) (51) Petroleum revenue tax - (145) - (145) Income tax (690) (148) (44) (882) ------------- --------- ----------- ------- Results of operations $ 1,191 $ 221 $ 82 $ 1,494 ============= ========= =========== =======
2003 ------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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) Asset retirement obligation accretion (23) (39) (1) (63) Petroleum revenue tax - (97) - (97) Income tax (673) (93) (24) (790) ------------- -------- ---------- ------- Results of operations $ 954 $ 139 $ 44 $ 1,137 ============= ======== ========== =======
2002 ------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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 ============= ========= ========== ========
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. 94 SUPPLEMENTARY OIL & GAS INFORMATION 2004 ANNUAL REPORT 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:
2004 ------------------------------------------------------------- OFFSHORE (millions of Canadian dollars) NORTH AMERICA NORTH SEA WEST AFRICA TOTAL - ------------------------------ ------------- --------- ----------- ----- Future cash inflows $ 31,727 $ 15,526 $ 5,249 $ 52,502 Future production costs (10,995) (6,302) (1,137) (18,434) Future development and site restoration costs (2,944) (2,832) (631) (6,407) Future income taxes (6,438) (3,783) (1,242) (11,463) ------------- --------- ----------- -------- Future net cash flows 11,350 2,609 2,239 16,198 10% annual discount for timing of future cash flows (4,385) (691) (634) (5,710) ------------- --------- ----------- -------- Standardized measure of future net cash flows $ 6,965 $ 1,918 $ 1,605 $ 10,488 ============= ========= =========== ========
2003 ----------------------------------------------------------- Offshore (millions of Canadian dollars) North America North Sea 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 ------------------------------------------------------------ Offshore (millions of Canadian dollars) North America North Sea 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 ============= ========= =========== ========
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) 2004 2003 2002 - ------------------------------ ---- ---- ---- Sales of oil and natural gas produced, net of production costs $ (4,331) $ (3,582) $ (2,510) Net changes in sales prices and production costs (553) (2,750) 8,453 Extensions, discoveries and improved recovery 2,120 1,360 972 Changes in estimated future development costs (894) (346) (1,284) Purchases of proved reserves in place 1,386 594 4,973 Sales of proved reserves in place (20) (8) (494) Revisions of previous reserve estimates 1,431 144 360 Accretion of discount 1,558 2,000 794 Changes in production timing and other 1,357 (1,411) 502 Net change in income taxes (997) 426 (4,723) -------- -------- -------- Net change 1,057 (3,573) 7,043 Balance - beginning of year 9,431 13,004 5,961 -------- -------- -------- Balance - end of year $ 10,488 $ 9,431 $ 13,004 ======== ======== ========
95 EX-99 6 ex-5form40f_2004.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 30th day of March, 2005. SIGNED "John G. Langille" - ---------------------------------------- John G. Langille President (Principal Executive Officer), Canadian Natural Resources Limited EX-99 7 ex-6form40f_2004.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 30th day of March, 2005. SIGNED "Douglas A. Proll" - ----------------------------------------- Douglas A. Proll Senior Vice President, Finance (Principal Financial Officer), Canadian Natural Resources Limited EX-99 8 ex-7form40f_2004.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, 2004 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 30th day of March, 2005. SIGNED "John G. Langille" - ---------------------------------------- John G. Langille President (Principal Executive Officer), Canadian Natural Resources Limited EX-99 9 ex-8form40f_2004.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, 2004 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: 3. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 4. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. DATED this 30th day of March, 2005. SIGNED "Douglas A. Proll" - ------------------------------------------------------------- Douglas A. Proll Senior Vice President, Finance (Principal Financial Officer), Canadian Natural Resources Limited EX-23 10 ex-9form40f_2004.txt EXHIBIT 9 EXHIBIT 9 --------- [GRAPHIC OMITTED] - -------------------------------------------------------------------------------- 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 18, 2005, with respect to the consolidated financial statements of Canadian Natural Resources Limited included in its (i) Annual Report (Form 40-F) for the year ended December 31, 2004 and (ii) Registration Statement on Form F-9 (Registration No. 333-104919), filed with the Securities and Exchange Commission. /s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP Calgary, Alberta February 18, 2005 PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity. EX-23 11 ex-10form40f_2004.txt EXHIBIT 10 EXHIBIT 10 ---------- [GRAPHIC OMITTED] [Sproule Associates Limited Letterhead] Ref.: 1808.15300 March 18, 2005 Canadian Natural Resources Limited 2500, 855 Second Street SW Calgary AB T2P 4J8 RE: CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS To Whom it May Concern: 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, 2004 and (ii) Registration Statement on Form F-9 (Registration No. 333-104919), filed with the Securities and Exchange Commission. Sincerely, Signed by Harry J. Helwerda, P.Eng. 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 TOLL FREE: 1-877-777-6135 INFO@SPROULE.COM, WWW.SPROULE.COM EX-23 12 ex-11form40f_2004.txt EXHIBIT 11 EXHIBIT 11 ---------- [GRAPHIC OMITTED] [RYDER SCOTT COMPANY LETTERHEAD] LETTER OF CONSENT TO: United States Securities and Exchange Commission RE: CANADIAN NATURAL RESOURCES LIMITED ("CNRL") - REGISTRATION STATEMENT ON FORM F-9 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, 2004 and (ii) Registration Statement on Form F-9 (Registration No. 333-104919), filed with the Securities and Exchange Commission. /s/ RYDER SCOTT COMPANY - CANADA RYDER SCOTT COMPANY - CANADA Calgary, Alberta March 18, 2005 EX-23 13 ex-12form40f_2004.txt EXHIBIT 12 EXHIBIT 12 ---------- [GRAPHIC OMITTED] Gilbert Laustsen Jung Associates Ltd. Petroleum Consultants 4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2 (403) 266-9500 Fax (403) 262-1855 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We consent to the use of our report with respect to the oil sand mining reserves data of Canadian Natural Resources Limited incorporated by reference in its (i) Annual Report (Form 40-F) for the year ended December 31, 2004 and (ii) Registration Statement on Form F-9 (Registration No. 333-104919), filed with the Securities and Exchange Commission. The reserves were assigned as of February 9, 2005. Yours very truly, GILBERT LAUSTSEN JUNG ASSOCIATES LTD. ORIGINALLY SIGNED BY James H. Willmon, P. Eng. Vice-President Dated: March 18, 2005 Calgary, Alberta -----END PRIVACY-ENHANCED MESSAGE-----