EX-99 3 ex1-form40f_2003.txt EXHIBIT 1 EXHIBIT 1 --------- CANADIAN NATURAL RESOURCES LIMITED ANNUAL INFORMATION FORM APRIL 2, 2004 1 TABLE OF CONTENTS DEFINITIONS....................................................................2 SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................3 THE COMPANY....................................................................4 GENERAL DEVELOPMENT OF THE BUSINESS............................................5 REGULATORY MATTERS.............................................................6 COMPETITIVE MATTERS............................................................8 ENVIRONMENTAL MATTERS..........................................................8 DESCRIPTION OF THE BUSINESS....................................................9 A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES...........................10 DRILLING ACTIVITY....................................................11 PRODUCING OIL AND GAS WELLS..........................................12 PRESENT ACTIVITIES...................................................12 NORTHEAST BRITISH COLUMBIA...........................................12 NORTHWEST ALBERTA....................................................13 NORTH ALBERTA........................................................14 HORIZON OIL SANDS PROJECT............................................16 SOUTH ALBERTA........................................................17 SOUTHEAST SASKATCHEWAN...............................................18 UNITED KINGDOM NORTH SEA.............................................18 OFFSHORE WEST AFRICA.................................................19 COTE D'IVOIRE........................................................19 ANGOLA...............................................................20 B. CRUDE OIL AND NATURAL GAS RESERVES.......................................20 C. RECONCILIATION OF CHANGES IN NET RESERVES................................25 D. CRUDE OIL AND NATURAL GAS PRODUCTION.....................................26 E. HISTORICAL DRILLING ACTIVITY BY PRODUCT..................................29 F. CAPITAL EXPENDITURES.....................................................30 G. NON-RESERVE ACREAGE......................................................32 H. DEVELOPED ACREAGE........................................................32 SELECTED FINANCIAL INFORMATION................................................33 MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................34 DIVIDEND HISTORY..............................................................34 DIRECTORS AND OFFICERS........................................................35 ADDITIONAL INFORMATION........................................................38 SCHEDULE "A"..................................................................40 SCHEDULE "B"..................................................................43 CURRENCY Unless otherwise indicated, all dollar figures stated in this Annual Information Form represent Canadian dollars. 2 DEFINITIONS The following are definitions of selected abbreviations used in this Annual Information Form: "ARTC" means Alberta Royalty Tax Credit. "BBL" or "BARREL" means 34.972 Imperial gallons or 42 U.S. gallons. "BCF" means one billion cubic feet. "BBLS/D" means barrels per day. "CANADIAN NATURAL RESOURCES LIMITED", "CANADIAN NATURAL", "CNRL" or "COMPANY" means Canadian Natural Resources Limited and includes, where applicable, reference to subsidiaries of and partnership interests held by Canadian Natural Resources Limited and its subsidiaries. "FPSO" means floating production, storage and off-take vessel. "GROSS ACRES" means the total number of acres in which the Company holds a working interest or the right to earn a working interest. "GROSS WELLS" means the total number of wells in which the Company has a working interest. "MBBLS" means one thousand barrels. "MCF" means one thousand cubic feet. "MCF/D" means one thousand cubic feet per day. "MMBBLS" means one million barrels. "MMBTU" means one million British thermal units. "MMCF" means one million cubic feet. "MMCF/D" means one million cubic feet per day. "NGLS" means natural gas liquids. "NET ACRES" refers to gross acres multiplied by the percentage working interest therein owned or to be owned by the Company. "NET WELLS" refers to gross wells multiplied by the percentage working interest therein owned or to be owned by the Company. "SAGD" means steam-assisted gravity drainage. "UNDEVELOPED LAND" or "NON-RESERVE ACREAGE" refers to lands on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas. "WORKING INTEREST" means the interest held by the Company in a crude oil or natural gas property, which interest normally bears its proportionate share of the costs of exploration, development, and operation as well as any royalties or other production burdens. "WTI" means West Texas Intermediate. Natural gas is converted to oil equivalent at the rate of six thousand cubic feet equals one barrel of oil equivalent. 3 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this document or incorporated herein by reference may constitute "forward-looking statements" within the meaning of the United States Private Litigation Reform Act of 1995. These forward-looking statements can generally be identified as such because of the context of the statements including words such as the Company "believes", "anticipates", "expects", "plans", "estimates", or words of a similar nature. The forward-looking statements are based on current expectations and are subject to known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others: the general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; the foreign currency exchange rates; the economic conditions in the countries and regions in which the Company conducts business; the political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the industry capacity; the ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition, availability and cost of seismic, drilling and other equipment; the ability of the Company to complete its capital programs; the ability of the Company to transport its products to market; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the operating hazards and other difficulties inherent in the exploration for and production and sale of oil and natural gas; the availability and cost of financing; the success of exploration and development activities; the timing and success of integrating the business and operations of acquired companies; the production levels; the uncertainty of reserve estimates; the actions by governmental authorities; the government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations); the site restoration costs; and other circumstances affecting revenues and expenses. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors, and management's course of action would depend upon its assessment of the future considering all information then available. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of important factors is not exhaustive. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. The Company assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. 4 THE COMPANY Canadian Natural Resources Limited was incorporated under the laws of the Province of British Columbia on November 7, 1973 as AEX Minerals Corporation (N.P.L.) and on December 5, 1975 changed its name to Canadian Natural Resources Limited. CNRL was continued under the COMPANIES ACT OF ALBERTA on January 6, 1982 and was further continued under the BUSINESS CORPORATIONS ACT (Alberta) on November 6, 1985. The head, principal and registered office of the Company is located in Calgary, Alberta, Canada at 2500, 855 - 2nd Street S.W., T2P 4J8. CNRL formed a wholly owned subsidiary, CanNat Resources Inc. ("CanNat") in January 1995. Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding shares of Sceptre Resources Limited ("Sceptre") in September 1996 and in January 1997, Sceptre and CanNat amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name CanNat Resources Inc. Pursuant to an Offer to Purchase all of the outstanding shares, the Company completed the acquisition of Ranger Oil Limited, including its subsidiaries, ("Ranger") in July 2000. On October 1, 2000 Ranger and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited. Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding shares of Rio Alto Exploration Ltd. ("RAX") in July 2002. On January 1, 2003 RAX and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited. On January 1, 2004 CanNat and the Company amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources Limited. The material operating subsidiaries of the Company, each of which is directly or indirectly wholly-owned, and their jurisdiction of incorporation are as follows: NAME OF COMPANY JURISDICTION OF INCORPORATION --------------- ----------------------------- CNR (ECHO) Resources Inc. Alberta CNR International (U. K.) Developments Limited England CNR International (U. K.) Limited England CNR International Cote d'Ivoire SARL Cote d'Ivoire Renata Resources Inc. Alberta CNRL as the managing partner and CNR (ECHO) Resources Inc. and Renata Resources Inc. are the partners of Canadian Natural Resources, a general partnership. Canadian Natural Resources as the managing partner and Renata Resources Inc. and CNRL are partners of Canadian Natural Resources Northern Alberta Partnership, a general partnership. The two partnerships hold the Canadian crude oil and natural gas properties of CNRL. CNRL also has a 15 per cent interest in Cold Lake Pipeline Ltd., which is the general partner of Cold Lake Pipeline Limited Partnership of which CNRL has a 14.7 per cent interest. The consolidated financial statements of CNRL include the accounts of the Company and all of its subsidiaries and partnerships. 5 GENERAL DEVELOPMENT OF THE BUSINESS CNRL's business is the acquisition of interests in crude oil and natural gas rights and the exploration, development, production, marketing and sale of crude oil and natural gas. The Company initiates, operates and maintains a large working interest in a majority of the prospects in which it participates. CNRL's objective is to increase cash flow and earnings through the development of its existing crude oil and natural gas properties and through the discovery and acquisition of new reserves. The Company's principal regions of crude oil and natural gas operations are in the Western Canadian Sedimentary Basin, the United Kingdom (the "UK") sector of the North Sea and Offshore West Africa. The Company has a full complement of management, technical and support staff to pursue these objectives. As at December 31, 2003 the Company had 1671 full time employees in North America and 204 full time employees in its international operations. In 2001, the Company completed 121 transactions in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate expenditure of $582.2 million. These properties are located in the Company's principal operating regions and are comprised of producing and non-producing leases together with related facilities. In addition, the Company disposed of non-operated properties not located in the Company's core regions for proceeds of $63.0 million, including a large portion of the properties acquired with Ranger in the United States Gulf Coast. On July 24, 2001, the Company issued US $400.0 million of 10 year 6.70 per cent unsecured notes maturing July 15, 2011 pursuant to a prospectus supplement dated July 19, 2001 to the short form shelf prospectus dated July 6, 2001. Pursuant to a prospectus supplement dated January 15, 2002 to the short form shelf prospectus dated July 6, 2001, the Company issued on January 23, 2002, US $400.0 million of 30 year 7.20 per cent unsecured notes maturing January 15, 2032. In July 2002, pursuant to the terms of a Plan of Arrangement, the Company acquired 100 per cent of RAX. The total purchase price was $2,393.2 million, comprised of $850.0 million in cash, $522.4 million attributable to the issue of 10,008,218 common shares of the Company, and the assumption of $936.3 million of debt and $84.5 million of working capital deficiency. The acquisition provided the Company with a new core region for natural gas exploration and exploitation activities in Northwest Alberta. The RAX properties include approximately 2.9 million net acres of undeveloped lands and provide additional opportunities for the Company to increase its production and reserves of natural gas and natural gas liquids. The acquisition added additional production, which averaged 376 million cubic feet per day of natural gas and 11 thousand barrels per day of crude oil and natural gas liquids during the second half of 2002 and 2-D and 3-D seismic of 57,820 kilometres and 14,565 square kilometres respectively. Future exploration and development projects will take advantage of the large undeveloped land base, high quality seismic database information and excess capacity within existing facilities. The acquisition solidified the Company as the second largest producer of natural gas in Canada and the second largest undeveloped landholder in western Canada. During 2002, the Company completed 128 transactions in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate expenditure of $516.3 million. These properties are located in the Company's principal operating regions and are comprised of producing and non-producing leases together with related facilities. 6 In addition, the Company disposed of non-operated properties not located in the Company's core regions for proceeds of $76.1 million. On September 16, 2002, the Company issued US $350.0 million of 10 year 5.45 per cent unsecured notes maturing October 1, 2012 and US $350.0 million of 31 year 6.45 per cent unsecured notes maturing June 30, 2033 pursuant to a prospectus supplement dated September 9, 2002 to a short form shelf prospectus dated August 16, 2002. During 2003, the Company completed 111 transactions in the normal course to acquire additional interests in crude oil and natural gas properties at an aggregate expenditure of $355.3 million. These properties are located in the Company's principal operating regions and are comprised of producing and non-producing leases together with related facilities. In addition, the Company disposed of non-operated properties not located in the Company's core regions for proceeds of $19.3 million. On February 18, 2004 the Company acquired certain resource properties located in East Central Alberta and Saskatchewan (collectively known as the Petrovera Partnership) for aggregate consideration of $701 million. In a separate transaction, the Company sold specific resource properties in the Petrovera Partnership, representing approximately one third of the total acquisition, to another independent producer for proceeds of $234 million, resulting in a net cost of $467 million for the retained properties. The net current production from the working interests retained by the Company was approximately 27.5 mbbl/d of heavy oil and 9 mmcf/d of natural gas together with volumes associated with royalty interests of 1.2 mbbl/d of heavy oil and 2 mmcf/d of natural gas. All of the retained properties are situated in the Company's core region of North Alberta. REGULATORY MATTERS The Company's business is subject to regulations generally established by government legislation and governmental agencies. The regulations are summarized in the following paragraphs. CANADA The petroleum and natural gas industry in Canada operates under various government legislation and regulations, which govern exploration, development, production, refining, marketing, prevention of waste and other activities. The Company's Canadian properties are located in Alberta, British Columbia, Saskatchewan, Manitoba and the Northwest Territories. Most of these properties are held under leases/licences obtained from the respective provincial or federal governments, which give the holder the right to explore for and produce crude oil and natural gas. The remainder of the properties are held under freehold (private ownership) lands. Conventional petroleum and natural gas leases issued by the provinces of Alberta, Saskatchewan and Manitoba have a primary term from two to five years, and British Columbia leases/licences presently have a term of up to ten years. Those portions of the leases that are producing or are capable of producing at the end of the primary term will "continue" for the productive life of the lease. The exploration licences in the Northwest Territories are administered by the Federal Government and only grant the right to explore. They have initial terms of four to five years. 7 A Commercial Discovery Licence must be obtained in order to produce crude oil and natural gas, which requires the approval of a satisfactory development plan. An oil sands permit and oil sands primary lease is issued for five and fifteen years respectively. If the minimum level of evaluation of an oil sands permit is attained, a primary oil sands lease will be issued out of the permit. A primary oil sands lease is continued based on the minimum level of evaluation attained on such lease. Continued primary oil sands leases that are designated as "producing" will continue for their productive lives while those designated as "non-producing" can be continued by payment of escalating rentals. The provincial governments regulate the production of crude oil and natural gas as well as the removal of natural gas and natural gas liquids from each province. Government royalties are payable on crude oil and natural gas production from leases owned by the province. The royalties are determined by regulation and are generally calculated as a percentage of production varied by a number of different factors including selling prices, production levels, recovery methods, transportation and processing costs, location and date of discovery. The Company is subject to federal and provincial income taxes in Canada at a combined rate of approximately 41 per cent after allowable deductions. UNITED KINGDOM Under existing law, the UK Government has broad authority to regulate the petroleum industry, including the power to regulate exploration, development, conservation and rates of production. Production from offshore fields as defined by applicable legislation, whose development was approved prior to April 1, 1982, were subject to Royalty of 12.5 per cent on or after deduction of certain allowances. Fields receiving development approval after April 1, 1982 were not subject to Royalty. On November 27, 2002, the UK Government announced the elimination of Royalty effective January 1, 2003. Crude oil and natural gas fields granted development approval before March 16, 1993 are subject to UK Petroleum Revenue Tax ("PRT") of 50 per cent charged on crude oil and natural gas profits. Crude oil and natural gas fields granted development approval on or after March 16, 1993 are exempted from PRT. Profits for PRT purposes are calculated on a field-by-field basis by deducting field operating costs and field development costs from production and third party tariff revenue. In addition, certain statutory allowances are available, which may reduce the PRT payable. The Company is subject to UK Corporation Tax ("CT") on its UK profits as adjusted for CT purposes. PRT paid is a deductible for CT purposes. The current CT rate, which became effective April 1, 1999, is 30 per cent. On April 17, 2002, the UK Government, in its 2002 budget speech by the UK Chancellor of the Exchequer, announced changes to taxation policies on UK North Sea crude oil and natural gas production. A supplementary CT charge of 10 per cent, charged on the same profits as calculated for `normal' CT but excluding any deduction for financing costs, was added to the current 30 per cent CT charge. Also the deduction for expenditures on capital items was changed from 25 per cent per annum to 100 per cent in the year incurred. OFFSHORE WEST AFRICA Terms of licences, including royalties and taxes payable on production or profit sharing arrangements, vary by country and in some countries by concession within each country. For instance, production from the Kiame field, on Block 4 in Angola, was subject to a 6 per cent 8 royalty on gross income and 50 per cent Petroleum Income Tax, which equates to 7 per cent calculated on the Company's gross income. Development of the Espoir field on CI-26, Cote d'Ivoire, is under the terms of a production sharing arrangement that provides that tax or royalty payments to the Government are deemed to be met from the Government's share of profit oil (See "Principal Crude Oil and Natural Gas Properties - Offshore West Africa"). Any changes in government policies or operating environment in the countries where the Company conducts business could have a significant impact on the Company's business ventures in such jurisdictions. Risks of foreign operations include, but are not necessarily limited to, changes of laws affecting foreign ownership, government participation, taxation, royalties, duties, rates of exchange, inflation, exchange control, repatriation of earnings and domestic or international unrest. The effect of changes in any of these factors cannot be accurately predicted. COMPETITIVE MATTERS The crude oil and natural gas industry, domestically and in the international arena, is highly competitive by nature. The Company must compete with integrated oil and natural gas companies and independent producers and marketers of crude oil and natural gas products in all aspects of the Company's business. This competition extends to exploration, property and asset acquisition and the selling of the Company's crude oil and natural gas products. The financial strength of some of the Company's competitors may be greater than that of the Company. ENVIRONMENTAL MATTERS The Company carries out its activities in compliance with all relevant regional, national and international regulations and best industry practice. Environmental specialists in the UK and Canada review the operations of the Company's world-wide interests and report on a regular basis to the senior management of the Company, which in turn reports on environmental matters directly to the Health, Safety and Environmental Committee of the Board of Directors. The Company regularly meets with, and submits to inspections by the various governments in the regions where the Company operates. At present, the Company believes that it meets all existing environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet current environmental protection requirements. Since these requirements apply to all operators in the crude oil and natural gas industry, it is not anticipated that the Company's competitive position within the industry will be adversely affected. The Company has internal procedures designed to ensure that the environmental aspects of new acquisitions and developments are taken into account prior to proceeding. The Company's environmental plan and operating guidelines focus on minimizing the environmental impact of field operations while meeting regulatory requirements and corporate standards. The Company's proactive program includes: an annual environmental compliance audit and inspection program of our operating facilities; an aggressive suspended well inspection program to support future development or eventual abandonment; appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; an effective surface reclamation program; progressive due diligence related to groundwater monitoring; prevention of and reclamation of spill sites, greenhouse gas reduction, and flaring and venting reduction. Canadian Natural participates in Canada's Climate Change Voluntary Challenge & Registry Inc. The Company has participated in the Canadian Association of Petroleum Producers (CAPP) Stewardship Program since 2000 and is currently a Gold Level Reporter. Canadian Natural 9 continues to invest in proven and new technologies and in improved operating strategies that will help us achieve our overall goal of a net reduction of greenhouse gas emissions per unit of production. The costs incurred by the Company for compliance with environmental matters and site restoration costs amount to less than 3 per cent of the total exploration and development expenditures incurred by the Company in each of the years ended December 31, 2003, 2002, and 2001. DESCRIPTION OF THE BUSINESS CNRL is a Canadian based senior independent energy company engaged in the acquisition, exploration, development, production, marketing and sale of crude oil, natural gas liquids and natural gas. The Company's principal core regions of operations are western Canada, the United Kingdom sector of the North Sea and Offshore West Africa. The Company focuses on exploiting its core properties and actively maintaining cost controls. Whenever possible CNRL takes on significant ownership levels, operates the properties and attempts to dominate the local land position and operating infrastructure. The Company has grown through a combination of internal growth and strategic acquisitions. Acquisitions are made with a view to either entering new core regions or increasing dominance in existing core regions. The Company's business approach is to maintain large project inventories and production diversification among each of the commodities it produces: namely natural gas, NGLs, light oil, Pelican Lake oil, primary heavy oil and thermal heavy oil. The Company's operations are centred on balanced product offerings, which together provide complementary infrastructure and balance throughout the business cycle. Natural gas is the largest single commodity sold, accounting for 47 per cent of 2003 production. Virtually all of the Company's natural gas and natural gas liquids production is located in the Canadian provinces of Alberta and British Columbia and is marketed in Canada and the United States. Light oil and NGLs, representing 25 per cent of 2003 production, is located principally in the Company's North Sea and Offshore West Africa properties, with additional production in the Provinces of Saskatchewan, British Columbia and Alberta. Primary and thermal heavy oil operations in the Provinces of Alberta and Saskatchewan account for 23 per cent of 2003 production. Other heavy oil, which accounts for 5 per cent of 2003 production, is produced from the Pelican Lake area in north Alberta. This production, which has medium oil netback characteristics, is developed through a staged horizontal drilling program. Midstream assets, comprised of three crude oil pipelines and an electricity co-generation facility, provide cost effective infrastructure supporting the heavy and medium oil operations. CNRL expects its ownership of oil sands leases near Ft. McMurray, Alberta to provide a basis for long-term synthetic oil production growth. As a result of the Company's core undeveloped land base of 11.3 million net acres in western Canada, its international concessions and the Alberta oil sands leases, the Company believes it has sufficient project portfolios in each of the product offerings to provide growth for the next several years. 10 A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES Set forth below is a summary of the principal crude oil and natural gas properties as at December 31, 2003. The information is proportionate to the working interests and royalty interests owned by the Company.
2003 AVERAGE YEAR ENDED DAILY DECEMBER 31, INFRASTRUCTURE PRODUCTION RATES 2003 AS AT DECEMBER 31, 2003 ------------------ ----------------- ------------------------------- BATTERIES/ COMPPRESSORS & OIL & NATURAL UNDEVELOPED PIPELINE PLANTS/ NGLs GAS ACREAGE (thousand PLATFORMS REGION Mbbls MMcf (thousands) miles) /FPSO NORTH AMERICA Northeast B. C. 6.7 372.3 1,566 2.3 8/ 74/ --/ -- Northwest Alberta 11.1 261.3 1,681 2.2 8/ 29/ --/ -- North Alberta 136.7 462.4 5,627 6.7 23/ 97/ --/ -- Horizon Oil Sands -- -- 117 -- --/ --/ --/ -- South Alberta 10.9 141.9 673 3.3 34/ 61/ --/ -- SE Saskatchewan 9.2 3.4 147 -- 35/ --/ --/ -- Non - core regions 0.3 3.4 1,604 -- --/ --/ --/ -- INTERNATIONAL North Sea 56.9 45.6 1,920 0.1 --/ --/ 4/ 2 Offshore West Africa Angola -- -- 610 -- --/ --/ --/ -- Cote d'Ivoire 10.6 8.4 333 -- --/ --/ --/ 1 South Africa -- -- 5,550 -- --/ --/ --/ -- ---------------------------------------------------------------------------------------------- TOTAL 242.4 1,298.7 19,828 14.6 108/ 261/ 4/ 3 ----------------------------------------------------------------------------------------------
11 DRILLING ACTIVITY Set forth below is a summary of the drilling activity, excluding stratigraphic test and service wells, of the Company for each of the last two fiscal years up to December 31, 2003 by geographic region:
2003 ------------------------------------------------------------------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL ------------------------------------------------------------------------------------------------------------------------- CANADA 15.5 13.3 28.8 67.8 9.1 76.9 Northeast B. C. 31.7 11.8 43.5 69.9 7.9 77.8 Northwest Alberta 57.5 26.6 84.1 531.6 37.9 569.5 North Alberta 33.0 4.0 37.0 387.9 5.0 392.9 South Alberta -- -- -- 26.9 -- 26.9 Southeast Saskatchewan -- -- -- 0.4 -- 0.4 Non - core regions NORTH SEA -- 1.0 1.0 11.1 0.8 11.9 OFFSHORE WEST AFRICA Cote d'Ivoire 0.7 -- 0.7 0.7 -- 0.7 Angola -- 0.6 0.6 -- -- -- ------------------------------------------------------------------------------------------------------------------------- TOTAL 138.4 57.3 195.7 1,096.3 60.7 1,157.0 ------------------------------------------------------------------------------------------------------------------------- 2002 ------------------------------------------------------------------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL ------------------------------------------------------------------------------------------------------------------------- CANADA 16.8 4.4 21.2 25.4 -- 25.4 Northeast B. C. 3.9 3.0 6.9 6.1 -- 6.1 Northwest Alberta 31.5 6.0 37.5 278.1 8.6 286.7 North Alberta 12.0 -- 12.0 40.6 2.5 43.1 South Alberta -- -- -- 4.3 1.0 5.3 Southeast Saskatchewan NORTH SEA 0.4 -- 0.4 4.5 -- 4.5 OFFSHORE WEST AFRICA Cote D'Ivoire 0.6 0.9 1.5 1.8 0.6 2.4 ------------------------------------------------------------------------------------------------------------------------- TOTAL 65.2 14.3 79.5 360.8 12.7 373.5 ------------------------------------------------------------------------------------------------------------------------- 2001 ------------------------------------------------------------------------------------------------------------------------- NET EXPLORATORY NET DEVELOPMENT PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL ------------------------------------------------------------------------------------------------------------------------- CANADA 13.1 4.5 17.6 63.5 5.0 68.5 Northeast B. C. 3.0 1.0 4.0 2.0 -- 2.0 Northwest Alberta 60.7 8.1 68.8 231.3 12.7 244.0 North Alberta 1.4 -- 1.4 324.9 -- 324.9 South Alberta -- -- -- 4.0 -- 4.0 Southeast Saskatchewan -- -- -- -- -- -- Non - core areas UNITED STATES -- 0.8 0.8 0.1 -- 0.1 NORTH SEA -- 0.2 0.2 2.2 -- 2.2 OFFSHORE WEST AFRICA Cote D'Ivoire 0.6 -- 0.6 0.6 -- 0.6 Angola -- -- -- -- -- -- ------------------------------------------------------------------------------------------------------------------------- TOTAL 78.8 14.6 93.4 628.6 17.7 646.3 -------------------------------------------------------------------------------------------------------------------------
12 PRODUCING OIL & GAS WELLS Set forth below is a summary of the number of gross and net wells within the Company that were on production as of December 31, 2003:
----------------------------------------------------------------------------------------------------------------------- NATURAL GAS WELLS OIL WELLS TOTAL WELLS GROSS NET GROSS NET GROSS NET ----------------------------------------------------------------------------------------------------------------------- CANADA 757 610.4 220 159.4 977 769.8 Northeast B. C. 665 539.4 150 108.2 815 647.6 Northwest Alberta 2,583 1,980.1 4,162 3,611.9 6,745 5,592.0 North Alberta 3,415 2,686.5 1,003 891.1 4,418 3,577.6 South Alberta 677 56.0 292 97.0 969 153.0 Southeast Saskatchewan -- -- 1,084 707.9 1,084 707.9 Non - core regions UNITED STATES 4 0.5 2 0.2 6 0.7 NORTH SEA 5 0.4 91 74.5 96 74.9 OFFSHORE WEST AFRICA Cote d'Ivoire -- -- 5 2.9 5 2.9 Angola -- -- -- -- -- -- ----------------------------------------------------------------------------------------------------------------------- TOTAL 8,106 5,873.3 7,009 5,653.1 15,115 11,526.4 -----------------------------------------------------------------------------------------------------------------------
PRESENT ACTIVITIES At December 31, 2003, the Corporation was in the process of drilling 47 gross wells (45.3 net wells). Injection of emulsion into the first waterflood injector of a demonstration project in the Pelican Lake field commenced to determine potential improvements in sweep efficiency and thus ultimate recovery. Waterflooding in the remaining injectors and monitoring the field's response to injection continued. NORTHEAST BRITISH COLUMBIA This region comprises lands from south of Fort St. John, British Columbia to the northern border of British Columbia. Similar geological attributes extend throughout the region, producing light oil, natural gas liquids and natural gas. The Company holds working interests ranging up to 100 per cent and averaging 78 per cent in 2,780,070 gross (2,158,094 net) acres of producing and undeveloped land in the region. Crude oil reserves are found primarily in the Halfway or lower Halfway formation, while natural gas and associated natural gas liquids are found in numerous zones at depths reaching approximately 2,000 vertical meters. In the southern portion of the region, the Company owns natural gas producing and undeveloped lands in which the productive zones are at deeper depths up to 3,500 meters. The exploration strategy focuses on comprehensive evaluation through two-dimensional seismic, three-dimensional seismic and targeting economic geological areas close to existing infrastructure. Applying under-balanced, multi-leg horizontal drilling has also proven highly effective in this region. Natural gas production from the region averaged 372.3 million cubic feet per day for 2003 compared to the average of 450.6 million cubic feet per day produced for 2002. Crude oil and natural gas liquids production decreased to 6.7 thousand barrels per day in 2003 from an average of 7.4 thousand barrels per day in 2002. 13 This region also contains the Ladyfern Slave Point natural gas pool, which was placed on production in mid-2001. Prior to the first quarter of 2002, production from the pool had been restricted due to insufficient processing facilities and pipelines, with production exiting 2001 at approximately 150 million cubic feet per day. In the first quarter of 2002, additional facilities were constructed, which enabled the Company to increase production to approximately 210 million cubic feet per day in June 2002. In late August 2002, water encroachment resulted in the commencement of anticipated significant declines from the pool. At the end of 2002, production was at 100 million cubic feet per day, falling to approximately 31 million cubic feet per day in December 2003. Through the acquisition of Ranger in 2000, the Company acquired an interest and operatorship in extensive acreage adjacent to the northern border of this region. A further acquisition in the fourth quarter of 2001 resulted in the Company obtaining 100 per cent ownership in its producing natural gas assets and undeveloped land in the Helmet area of the region. Further development of this acreage will be enhanced through the facilities and infrastructure owned by the Company in the region. Having identified optimal drilling strategies in the region, the Company implemented a multi-well annual drilling program, which resulted in 35 wells being drilled in 2003. During 2003, the Company developed a new exploration and development program that targets natural gas found in the shallow Notikewin formation in the Fort St. John area. Wells drilled into this formation produce at rates of 500 to 700 thousand cubic feet per day. In combination with the Company's extensive land base and the recently reduced royalty rates in British Columbia, this shallow gas drilling program will add to the Company's opportunities in this region. During 2003 the Company drilled 5.1 (2002-2.1) net oil wells, 78.2 (2002-40.1) net natural gas wells, 0.0 (2002-1.0) net service wells and 22.4 (2002-4.4) net dry wells on its lands in this region for a total of 105.7 (2002-47.6) net wells. The Company held an average 93 per cent working interest in these wells. NORTHWEST ALBERTA The Company holds working interests ranging up to 100 per cent and averaging 81 per cent in 2,542,232 gross (2,066,138 net) acres of producing and undeveloped land in the region located along the border of British Columbia and Alberta west and north of Edmonton. The majority of the Company's holdings in the region were obtained through the Plan of Arrangement in 2002, which facilitated the acquisition of RAX. This region contains exceptional exploration and exploitation opportunities as well as substantial available capacity within an extensively owned and operated infrastructure. In this region, Canadian Natural produces liquids rich natural gas from multiple, often technically complex horizons, with formation depths ranging from 1,000 to 4,500 metres. The northern portion of this core region provides extensive multi-zone Cretaceous opportunities similar to the geology of the Company's North Alberta core region. The southern portion provides a significant opportunity in the regionally extensive Cretaceous Cardium zone. The Cardium is a complex, tight natural gas reservoir where high productivity may be achieved due to greater matrix porosity or natural fracturing. In this southern portion, Canadian Natural pursued a modest well drilling program in the first half of 2003 so that detailed geological, geophysical and engineering work could be completed and interpreted. A more extensive drilling program was commenced in the last quarter of 2003. Natural gas production from the region averaged 261.3 million cubic feet per day for 2003 compared to an average of 171.2 million cubic feet per day for 2002. Crude oil and natural gas liquids production increased to 11.1 thousand barrels per day in 2003 from 6.6 thousand barrels per day in 14 2002. During 2003 the Company drilled 3.7 (2002-2.1) net oil wells, 97.9 (2002-7.5) net natural gas wells, and 19.7 (2002-3.0) net dry wells on its lands in this region for a total of 121.3 (2002-12.6) net wells. The Company held an average 85 per cent working interest in these wells. The Company owns and operates significant production facilities in this region, many of which have excess capacity, providing for cost effective future expansion of operations. All of the facilities are in close proximity to sales facilities. NORTH ALBERTA The Company holds working interests ranging up to 100 per cent and averaging 82 per cent in 9,602,862 gross (7,896,464 net) acres of producing and undeveloped land in the region located north of Edmonton to Fort McMurray and east to the border with Saskatchewan and extending into western Saskatchewan. Over most of the region both sweet and sour natural gas reserves are produced from numerous productive horizons at depths up to approximately 1,500 meters. In the southwest portion of the region, natural gas liquids and light oil are also encountered at slightly deeper depths. The region continues to be one of the Company's largest natural gas producing regions, with natural gas production from the region amounting to 462.4 million cubic feet per day in 2003 compared to 419.8 million cubic feet per day in 2002. Crude oil and natural gas liquids production from this region increased to 136.7 thousand barrels per day in 2003 from 135.9 thousand barrels per day in 2002. Production of natural gas was impacted by the shut-in effective September 1, 2004 of approximately 11 million cubic feet per day in the Athabasca Wabiskaw-McMurray oil sands area pursuant to the decision of the Alberta Energy and Utilities Board. In the area near Lloydminster, Alberta, reserves of heavy oil (averaging 12(Degree) - 14(degree) API) and natural gas are produced through conventional vertical, slant and horizontal well bores from a number of productive horizons up to 1,000 meters deep. The energy required to flow the heavy oil to the wellbore in this type of heavy oil reservoir comes from solution gas. The oil viscosity and the reservoir quality will determine the amount of crude oil produced from the reservoir, which will vary from 3 to 20 per cent. A key component to maintaining profitability in the production of heavy oil is to be a low cost producer. The Company continues to achieve low costs producing heavy oil by holding a dominant position that includes a significant land base and an extensive infrastructure of batteries and disposal facilities. The price received for heavy oil is discounted from the benchmark WTI price and during the last quarter of 2000, this differential widened to historically high levels. As a result, the Company took a proactive stance and consciously reduced the number of heavy oil wells drilled in 2001, reduced heavy oil production by 15 thousand barrels per day beginning December 2001 and changed the steaming pattern at its Primrose facility. Following the return of the heavy oil differential to more historical levels, the Company brought most of this production back online and expanded its 2002 and 2003 drilling programs. The Company continues to monitor and develop the heavy oil market and work on strategies to eliminate some of the uncertainty surrounding this commodity pricing. Ranger owned significant land and production in this region, with much of its land being contiguous to the Company's holdings. With the operations combined in 2000, future development of the total lands in the region became more effective and provided opportunities for cost savings. As part of the acquisition of Ranger, the Company also acquired a 50 per cent interest in the ECHO Pipeline system, a crude oil transportation pipeline; and, in 2001 the Company acquired the remaining 50 per cent. The pipeline was extended north to the Company operated Beartrap field during 2001, enhancing further development of the Company's extensive holdings in the area. This pipeline was 15 capable of transporting 57 thousand barrels per day of hot unblended crude oil to sales facilities at Hardisty, Alberta and in 2003 its capacity was expanded to handle up to 72 thousand barrels per day. The ECHO Pipeline system is a high temperature, insulated pipeline that eliminates the requirement for field condensate blending. The pipeline enables the Company to transport its own production volumes at a reduced operating cost as well as earn third party transportation revenue. The ECHO Pipeline system, together with other midstream assets in which the Company has partial interests, permits the Company to transport in excess of 80 per cent of its heavy oil to the international mainline liquids pipelines. This transportation control enhances the Company's ability to control the full spectrum of costs associated with the development and marketing of its heavy oil. Production from the 100% owned Primrose and Wolf Lake fields located near Bonnyville, Alberta involves processes that utilize steam to increase the recovery of the oil. The two processes employed by the Company are cyclic steam stimulation and SAGD. Both recovery processes inject steam to heat the heavy oil deposits, reducing the oil viscosity and therefore improving its flow characteristics. There is also an infrastructure of gathering systems, a processing plant with a capacity of 60 thousand barrels per day and a 50 per cent interest in a co-generation facility capable of producing 84 megawatts of electricity for the Company's use and sale into the Alberta power grid at pool prices. In 2000, the Company successfully converted and tested two existing pads of wells from low-pressure steaming to high-pressure steaming. This conversion increased average production at the 20 existing wells from 100 to 190 barrels of crude oil per day per well. An additional 24 wells were drilled using the high-pressure steam process with initial production averaging 600 barrels of crude oil per day per well. These results have confirmed the benefits of converting the Primrose field to high-pressure steaming. In 2001, the Company received regulatory approval to convert an additional six low-pressure cyclic pads to high-pressure cyclic pads, and in 2002 received approval to take high-pressure steam methodologies throughout the field. Canadian Natural drilled 48 high-pressure wells in 2003, which will increase field production commencing in 2004. Additional development of the leases will be undertaken in phases over the next several years. A successful SAGD heavy oil project in which the Company holds a 50 per cent interest is also in operation in the Saskatchewan portion of this region. Included in the northern part of this region, approximately 200 miles north of Edmonton, are the Company's 100 per cent owned holdings at Pelican Lake. These lands contain reserves of 14(Degree)-17(Degree) API heavy oil. Operating costs are low due to no sand production or disposal requirements, the gathering and pipeline facilities in place and negligible water production and disposal. The Company has the major ownership position in the necessary infrastructure including roads, drilling pads, gathering and sales pipelines, batteries, gas plants and compressors to ensure future economic development of the large crude oil pool located on the lands. In the first quarter of 2001, the Company added to its holdings in this area through the acquisition of additional producing lands from another industry participant. Following this acquisition, the Company holds and controls in excess of 80 per cent of the known crude oil pool in this area. This field contains approximately three billion barrels of original oil-in-place but is only expected to achieve a 5 per cent recovery factor using existing primary technologies on the Company's developed leases. Hence, in 2002 the Company embarked upon an Enhanced Oil Recovery ("EOR") scheme using an emulsion flood to increase the ultimate recoveries from the field. The experimental Pelican Lake emulsion flood showed that the recovery mechanism was very efficient; however, response time is slow. In view of the slow response time, the Company has reverted to a waterflood scheme for this field, which will increase the overall recovery factor but not to the extent reached under an emulsion scheme. This waterflood will be implemented in phases with approximately 20 per cent of the field scheduled to be under waterflood by the end of 2004. The implementation plan will result in the conversion of existing producing wells into water injectors and the drilling of additional producing 16 wells. The Company will also examine opportunities to use emulsion flooding in conjunction with waterflooding to obtain the highest recovery factor while maximizing value. During 2003 in this region, the Company drilled 405.7 (2002 - 246.0) net oil wells, 183.4 (2002 - 62.4) net natural gas wells, 58.5 (2002 - 148.5) net stratigraphic tests wells, 5.0 (2002 - 2.5) net services wells and 64.5 (2002 - 15.0) net dry wells that were abandoned for a total of 717.1 (2002 - 474.4) net wells. The Company's average working interest in these wells was in excess of 93 per cent. The Company operates and owns significant infrastructure in the region as shown above and has additional interests in plants and compressors in the region that are operated by other companies. HORIZON OIL SANDS PROJECT Canadian Natural owns a 100 percent working interest in 116,596 gross acres in the Athabasca Oil Sands area of Northern Alberta. The Horizon Oil Sands Project ("the Horizon Project") is located on these leases, about 80-km north of Fort McMurray. The project includes surface oil sands mining, bitumen extraction, bitumen upgrading to produce a 34-36o API synthetic light crude oil ("SCO"), and associated infrastructure. The project is designed as a phased development. Major site clearing and pre-construction preparation activities will commence upon completed regulatory approval and project sanction in 2004 and construction would continue through 2012. Phase 1 production is planned to begin in the fourth quarter of 2008 at 110 thousand barrels per day of SCO. Phase 2 would increase production to 155 thousand barrels per day of SCO in 2010. Phase 3 would further increase production to 232 thousand barrels per day of SCO in 2012. These projected rates of production represent nominal design capacity. Canadian Natural will seek to maximize resource recovery and overall production through ongoing optimization of operations. The phased approach provides the Company with improved cost and project controls in terms of labour and materials management and directionally mitigates the effects of growth on local infrastructure. Total expected capital costs of the phased development are $8.0 billion to $8.5 billion, of which approximately $5.0 billion would be required for Phase 1. These costs are consistent with final actual costs incurred by other recent oil sands mining projects. When the Horizon Project is fully commissioned, operating costs - including sustaining capital - are expected to be in the range of $9 to $11 per barrel. Drilling to date indicates an estimated 16 billion barrels of bitumen-in-place on the Company's Athabasca Oil Sands Leases. Over its forty-year life span the Horizon Project is expected to recover about six billion barrels of bitumen. Additional surface mining and in-situ potential exists on the portion of leases not comprising the Horizon Project. No reserves from these leases are included in the Company's current reserves of crude oil and natural gas liquids pending final regulatory and corporate approvals, subsequent capital expenditures and initiation of production. Canadian Natural filed an application for regulatory approval of the Horizon Project in June 2002. The application included a comprehensive environmental impact assessment and a social and economic assessment and was accompanied by public consultation. A federal-provincial regulatory Joint Review Panel (the "Panel") examined the project in a public hearing in September 2003. The Panel issued its decision report in January 2004, finding that the Horizon Project is in the public interest. Subsequent to the Panel decision, the Company has received approval for the Horizon Project from the Alberta Energy and Utilities Board and the Cabinets of both the Government of Canada and Alberta. Further approvals pursuant to specific government acts and regulations are expected mid-2004. 17 Due to uncertainties about the long term cost implications of the Government of Canada climate change policies, in late 2002 Canadian Natural reduced its estimate of 2003 capital expenditures for the Horizon Project from $300 million to $211 million. Throughout the first half of 2003, Canadian Natural, along with other major energy project proponents and the Canadian Association of Petroleum Producers actively sought greater clarity from the federal government about the long-term climate change policy framework. Of particular concern was the period beyond 2012 when policies will be derived from Canada's negotiations for a second Kyoto implementation phase. In mid 2003 the Government of Canada acknowledged the need for greater clarity and established eight principles that will guide the Government of Canada's longer-term climate change policies. These eight guiding principles addressed the key concerns of Canadian Natural with regard to equability, efficiency, flexibility and competitiveness issues for the post-2012 period. Canadian Natural is using a structured system called Front End Loading to ensure that project definition is adequate and complete before proceeding with implementation. This system is used successfully worldwide to mitigate risk on large capital projects in a variety of industries. The process is well documented at every step and is audited by an independent organization. In June 2002, the Company commenced the Design Basis Memorandum (DBM), which is the second of three front-end engineering phases. The DBM was completed for all project components in February 2004. In August 2003, the Company commenced work on the third front-end engineering phase, Engineering Design Specifications (EDS), on those components where the DBM was complete. The EDS will provide sufficient definition for lump sum bids on various project components, and a final detailed cost estimate that will provide the basis of project sanction by the Company's Board of Directors. Completion of this phase is expected in the last quarter of 2004. During 2003, the Company drilled 370 (2002 - 293) stratigraphic test wells to further delineate the ore body and confirm resource quality and quantity. SOUTH ALBERTA The Company holds interests ranging up to 100 per cent and averaging 81 per cent in 1,726,760 gross (1,390,732 net) acres of producing and undeveloped land in the region principally located south and east of Calgary. Reserves of natural gas, condensate and light and medium gravity crude oil are contained in numerous productive horizons at depths up to 2,300 meters. Unlike the Company's other three natural gas producing regions, which have areas with limited or winter access only, drilling can take place in this region throughout the year. With a higher sales price for natural gas, it is economic to drill shallow wells in closer proximity to each other, which may have smaller overall reserves and lower productivity per well but will achieve a high return on capital employed with low drilling costs and longer life reserves The Company maintains a large inventory of drillable locations on its land base in this region. This region is in the most mature portion of the Western Canadian Sedimentary Basin and requires continual operational cost control through efficient utilization of existing facilities, flexible infrastructure design and consolidation of interests where appropriate. The Company's share of production averaged 10.9 (2002 - 9.0) thousand barrels of crude oil and natural gas liquids per day and 141.9 (2002- 145.8) million cubic feet of natural gas per day in 2003. 18 During 2003, the Company drilled a total of 4.4 (2002 - 1.0) net oil wells, 416.5 (2002 - 51.6) net natural gas wells and 9.0 (2002 - 2.5) net dry wells in this region for a total of 429.9 (2002 - 55.1) net wells. The Company's average working interest in these wells is in excess of 97 per cent. The wells are predominantly in areas where the Company already has gathering and processing facilities. SOUTHEAST SASKATCHEWAN The Williston Basin is located in Southeastern Saskatchewan with lands extending into Manitoba and North Dakota. This region was owned by Sceptre and became a core region of the Company in mid 1996 with the acquisition of Sceptre. The Company holds interests ranging up to 100 per cent and averaging 81 per cent in 273,371 gross (219,124 net) acres of producing and undeveloped lands in the region. The region produces primarily light sour crude oil from as many as seven productive horizons found at depths up to 2,700 meters. During 2003, net production to the Company averaged 9.2 (2002 - 9.4) thousand barrels of crude oil and natural gas liquids and 3.4 (2002 - 3.2) million cubic feet of natural gas per day in 2003. The Company drilled 26.9 (2002 - 4.3) net oil wells and no (2002 - 1.0) net dry wells in this region in 2003 for a total of 26.9 (2002 - 5.3) net wells. The Company's average working interest in these wells is 84 per cent. UNITED KINGDOM NORTH SEA The Company's wholly owned subsidiary CNR International (U.K.) Limited, formerly Ranger Oil (U.K.) Limited, has operated in the North Sea for 30 years and has developed a significant database, extensive operating experience and an experienced staff. The Company owns interests ranging from 7 per cent up to 100 per cent in 910,183 gross (638,749 net) acres of producing and non-producing properties in the UK sector of the North Sea. In 2003, the Company produced from 9 crude oil fields. The northerly fields are centered around the Ninian Field where the Company has an 87.1 per cent working interest. The central processing facility is connected to other fields including the Columba and Lyell Fields where the Company operates with working interests of 91.6 per cent to 100 per cent. In 2002, the Company completed property acquisitions in the northern North Sea that increased ownership levels in the Ninian, Murchison, Lyell and Columba Terraces Fields. As part of the transaction the Company also acquired an interest in the Strathspey Field and 12 licenses covering 20 exploration blocks and part blocks surrounding the Ninian and Murchison platforms. Increased ownership in the Brent and Ninian pipelines and the Sullom voe Terminal was also acquired. In 2003 the Company further consolidated its ownership with the acquisition of additional working interests in the Ninian and Columba Fields, associated facilities and adjacent exploration acreage. Ownership and operatorship levels in the North Sea are now similar to those levels found throughout the Company's other worldwide operations. The Company also receives tariff revenue from other field owners for the transportation and processing of crude oil and natural gas through the processing facilities. Opportunities for further long-reach well development on adjacent fields are provided from the existing processing facilities. In the central portion of the North Sea, in 2003 the Company increased its equity in the Banff Field to 87.6 per cent and took over as operator. The Company also owns a 45.7 per cent operated working interest in the Kyle Field. During 2003, production to the Company from this region averaged 56.9 (2002 - 38.8) thousand barrels of crude oil per day and 45.6 (2002 - 27.1) million cubic feet of natural gas per day. The Company drilled 11.1 (2002 - 4.9) net oil wells, 4.8 (2002 - 1.2) net service wells and 1.8 (2002 - 0.0) net dry wells in 2003 in this region for a total of 17.7 (2002 - 6.1) net wells. The Company's average working interest in these wells is 84 per cent. 19 OFFSHORE WEST AFRICA With the purchase of Ranger in 2000, the Company acquired interests in areas of crude oil and natural gas exploration and development offshore Cote d'Ivoire and Angola, West Africa. The Company owns working interests ranging from 50 per cent to 100 per cent in 1,685,151 gross (952,006 net) acres in those countries. The Company also has a 100 per cent interest in 5,550,428 acres offshore South Africa where it is shooting and evaluating seismic. COTE D'IVOIRE The Company owns interests in three exploration licences offshore Cote d'Ivoire comprising 336,758 net acres. During 2001, the Company increased its interest in Block CI-26, which contains the Espoir crude oil and natural gas field, to a 59 per cent operating interest. The Espoir field is located in water depths ranging from 100 to 700 meters. During the 1980s, the Espoir field produced approximately 31 million barrels of crude oil by natural depletion prior to relinquishment by the previous licencees in 1988. The government of Cote d'Ivoire approved a development plan to recover the remaining reserves and the Company will continue its exploitation and development of the field. The development of East Espoir, which includes the drilling of both producing and water injection wells from a single wellhead tower was completed in 2003. Finalization of development plans for the West Espoir field will be completed in 2004. Oil from the East Espoir field is produced into an FPSO with associated natural gas delivered onshore through a subsea pipeline for local power generation. During December 2002 a satellite pool, Emien, was drilled, but encountered no hydrocarbons. The Company drilled a second, satellite pool, Acajou, during the first half of 2003. The Acajou well encountered a reservoir with good quality and hydrocarbons but not of sufficient size to warrant tie-back to the Espoir FPSO. Further evaluation will be undertaken to determine if the Acajou structure extends across additional lands. In the first quarter of 2001, the Company drilled and tested the Baobab exploration prospect, identified on Block CI-40, in which the Company has a 58 per cent interest, eight kilometres south of the Espoir facilities. The well encountered hydrocarbons at a rate of 6.7 thousand barrels of crude oil per day. A second test well in 2002 also produced hydrocarbons at a rate in excess of 10 thousand barrels of crude oil per day. The Company established a field development plan, which was approved by the Government of Cote d'Ivoire in December 2002. In 2003 the Company awarded four major contracts for the development of the Baobab Field. These contracts included the deep water drilling rig to drill 8 producing and 3 water injection wells, the FPSO, supplies for the subsea equipment and the supply of pipeline and risers, and installation of the subsea infrastructure. Development commenced in late 2003 with the drilling of the first water injection well. The development continues for first oil planned at initial gross production rates of 45 thousand barrels per day in 2005, increasing with full development to 60 thousand barrels per day. To date political unrest in Cote d'Ivoire has had no impact on the Company's operations. The Company has developed contingency plans to continue Cote d'Ivoire operations from another nearby country if the situation warrants such a move. During 2003, net daily production to the Company averaged 10.6 (2002 - 6.0) thousand barrels of crude oil and 8.4 (2002 - 1.3) million cubic feet of natural gas. In 2003, the Company drilled 1.3 (2002 - 2.4) net oil wells, 2.0 (2002 - 0.6) net service wells and 0.0 (2002 - 1.2) net dry wells for a total of 3.3 (2002 - 4.2) net wells. The Company's average working interest in these wells is 67 per cent. 20 ANGOLA During 2002, Canadian Natural was awarded operatorship and a 50 per cent working interest in exploration Block 16 situated offshore The People's Republic of Angola. Canadian Natural obtained 3-D seismic over the entire Block 16 before obtaining title and identified two targets, Omba in the north and Zenza in the west central portion of the Block. The Company has a two well commitment over a four year time frame expiring August 31, 2006. The first well, Zenza-1, was drilled during the fourth quarter of 2003 and was not considered commercial. The second exploratory well is expected to be drilled in the first quarter of 2005 following analysis of the Zenza results and further seismic reprocessing. The Company also owned 100 per cent of and operated the offshore Kiame Field. The field produced from June 1998 to April 2002 through a leased FPSO. The field reached its economic limit of production and production ceased in April 2002. The wells were abandoned and the associated seabed equipment safely recovered during 2003. The Company also had a 25 per cent non-operating interest in Block 19, on which a 3-D seismic survey was completed in 1999. After interpretation of the seismic and drilling of a 25 per cent interest well in 2002 on Block 19, the Company determined the block was not economic to develop and relinquished its license on the block. B. CRUDE OIL AND NATURAL GAS RESERVES The Company retains independent qualified petroleum engineering consultants Sproule Associates Limited ("Sproule") to evaluate 100% of the Company's proved and proved and probable crude oil and natural gas reserves and prepare evaluation reports on the Company's total reserves ("Evaluation Reports"). The Company has been granted an exemption from the recently adopted National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") which prescribes the standards for the preparation and disclosure of reserves and reserves related information for companies listed on stock exchanges in Canada. This exemption allows the Company to substitute United States Securities and Exchange Commission ("SEC") requirements for certain disclosures required under NI 51-101. The primary difference between the two standards is the additional requirement under NI 51-101 to disclose both proved and proved plus probable reserves as well as related future net revenues using forecast prices and costs. The Company has disclosed proved reserves using constant prices and costs as mandated by the SEC and has elected to provide proved plus probable reserves and values under the same parameters as well as proved and proved plus probable reserves using forecast prices and costs as additional voluntary information. Another difference between the two standards lies in the definition of proved reserves. As discussed in the Canadian Oil and Gas Evaluation handbook ("COGEH"), the standards which NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. The Reserves Committee of the Board of Directors of the Company has met with Sproule and carried out the appropriate independent due diligence procedures with Sproule to review the qualifications of and procedures used by Sproule in determining the estimate of the Company's quantities and value of remaining petroleum and natural gas reserves. The following tables summarize the evaluations of reserves and estimated future net revenues at December 31, 2003. THE ESTIMATED FUTURE NET REVENUES CONTAINED IN THE FOLLOWING TABLES ARE NOT TO BE CONSTRUED AS A REPRESENTATION OF THE FAIR MARKET VALUE OF THE PROPERTIES TO WHICH THEY RELATE. THE ESTIMATED FUTURE NET REVENUES DERIVED FROM THE ASSETS ARE PREPARED PRIOR TO CONSIDERATION OF INCOME TAXES 21 AND EXISTING ASSET ABANDONMENT LIABILITIES. NO INDIRECT COSTS SUCH AS OVERHEAD, INTEREST AND ADMINISTRATIVE EXPENSES HAVE BEEN DEDUCTED FROM THE ESTIMATED FUTURE NET REVENUES. OTHER ASSUMPTIONS AND QUALIFICATIONS RELATING TO COSTS, PRICES FOR FUTURE PRODUCTION AND OTHER MATTERS ARE SUMMARIZED IN THE NOTES TO THE FOLLOWING TABLES. THERE IS NO ASSURANCE THAT THE PRICE AND COST ASSUMPTIONS CONTAINED IN EITHER THE CONSTANT OR FORECAST CASES WILL BE ATTAINED AND VARIANCES COULD BE SUBSTANTIAL. CRUDE OIL, NGL AND NATURAL GAS RESERVES (NET OF ROYALTIES)
CONSTANT PRICES AND COSTS ----------------------------------------------------------------------- NET NET CRUDE OIL & NGL RESERVE NATURAL GAS RESERVE VOLUMES (MMbbls) VOLUMES (Bcf) ----------------------------------- ---------------------------------- TOTAL TOTAL PROVED AND PROVED AND PROVED PROBABLE PROVED PROBABLE RESERVES RESERVES RESERVES RESERVES -------- -------- -------- -------- NORTH AMERICA Canada 588 857 2,425 2,917 United States -- -- 1 2 INTERNATIONAL United Kingdom 222 317 62 102 Cote d'Ivoire 85 133 64 72 -------------- ------------------- ------------- ------------------- TOTAL 895 1,307 2,552 3,093 ============== =================== ============= ===================
CRUDE OIL, NGL AND NATURAL GAS RESERVES
CONSTANT PRICES AND COSTS ------------------------------------------------------------------------- CRUDE OIL AND NATURAL GAS LIQUIDS (MMbbls) NATURAL GAS (Bcf) ------------------------------------ --------------------------------- GROSS NET GROSS NET ----- --- ----- --- Proved developed 568 509 2,725 2,198 Proved undeveloped 432 386 429 354 ---------------- ------------------ --------------- ---------------- Total proved reserves 1,000 895 3,154 2,552 Total proved and probable reserves 1,481 1,307 3,823 3,093 ================ ================== =============== ================
ESTIMATED FUTURE NET REVENUES
($Millions) CONSTANT PRICES AND COSTS --------------------------------------------------------------------- UNDISCOUNTED DISCOUNTED AT --------------------- -------------------------------------------- 10% 15% 20% --- --- --- Proved developed $21,079 $13,080 $11,222 $9,902 Proved undeveloped 6,370 3,037 2,273 1,752 --------------------- ------------- ------------- -------------- Total proved reserves 27,449 16,117 13,495 11,654 Total proved and probable reserves $36,981 $20,167 $16,460 $13,929 ===================== ============= ============= ==============
22 CRUDE OIL, NGL AND NATURAL GAS RESERVES
FORECAST PRICES AND COSTS --------------------------------------------------------------------- CRUDE OIL AND NATURAL NATURAL GAS (Bcf) GAS LIQUIDS (MMbbls) ----------------------------------- ----------------------------- GROSS NET GROSS NET ----- --- ----- --- Proved developed 563 511 2,706 2,184 Proved undeveloped 432 398 429 361 ----------------- ---------------- -------------- ------------- Total proved reserves 995 909 3,135 2,545 Total proved and probable reserves 1,480 1,332 3,797 3,079 ================= ================ ============== =============
ESTIMATED FUTURE NET REVENUES
($ Millions) FORECAST PRICES AND COSTS --------------------------------------------------------------------- UNDISCOUNTED DISCOUNTED AT --------------------- -------------------------------------------- 10% 15% 20% --- --- --- Proved developed $15,949 $ 9,819 $ 8,464 $ 7,511 Proved undeveloped 4,705 2,054 1,471 1,079 --------------------- ------------- ------------- -------------- Total proved reserves 20,654 11,873 9,935 8,590 Total proved and probable reserves $28,056 $14,893 $12,118 $10,247 ===================== ============= ============= ==============
NOTES 1. "Gross" reserves means the total working interest share of remaining recoverable reserves owned by the Company before deduction of royalties payable to others. 2. "Net" reserves mean the Company's gross reserves less all royalties payable to others plus royalties receivable from others. 3. "Proved developed" reserves were evaluated using SEC standards and can be expected to be recovered through existing wells with existing equipment and operating methods. SEC standards require that these be evaluated using year-end constant prices and costs and be disclosed net of royalties. The Company has also provided these reserves and their associated values using forecast prices and costs as well as before royalties as additional voluntary information. 4. "Proved undeveloped" reserves were evaluated using SEC standards and are expected to be recovered from new wells on undrilled acreage, or from existing wells where relatively major expenditures are required for the completion of these wells or for the installation of processing and gathering facilities prior to the production of these reserves. Reserves on undrilled acreage are limited to those drilling units offsetting productive wells that are reasonably certain of production when drilled. SEC standards require that these be evaluated using year-end constant prices and costs and be disclosed net of royalties. The Company has also provided these reserves and their associated values using forecast prices and costs as well as before royalties as additional voluntary information. 5. "Proved" reserves were evaluated using SEC standards and are those quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. SEC standards require that these be evaluated using year-end constant prices and costs and be disclosed net of royalties. The Company has also provided these reserves and their associated values using forecast prices and costs as well as before royalties as additional voluntary information. 6. "Total Proved and Probable" reserves were evaluated using the COGEH standards of NI 51-101 and are those reserves where there is at least a 50 per cent probability that the quantities actually recovered will equal or exceed the stated values. The Company has elected to disclose proved plus probable reserves and their associated values using both constant prices and costs as well as forecast prices and costs and has disclosed these before and net of royalties. The calculation of a probable reserves and value component by subtracting the proved reserves from the proved plus probable reserves may be subject to error due to the different standards applied in the determination of each value. The impact, however, is not material. 7. Canadian securities legislation and policies permit the disclosure, which is included or incorporated by reference herein under a multi-jurisdicitional disclosure system adopted by the SEC, of probable reserves which may not be disclosed in registration statements otherwise filed with the SEC. Probable reserves are generally believed to be less likely to be recovered than proved reserves. The reserve estimates, included or incorporated by reference in this Annual Information Form could be materially different from the quantities and values ultimately realized. 8. All values are shown in Canadian dollars. 23 9. The constant price and cost case assumes that prices in effect at the end of the year adjusted for quality and transportation as well as the 2003 costs are held constant over life. The constant price assumptions assume the continuance of current laws, regulations and operating costs in effect on the date of the Evaluation Report. Product prices have not been escalated beyond 2004. In addition, operating and capital costs have not been increased on an inflationary basis. The crude oil and natural gas constant prices used in the Evaluation Reports are as follows:
NATURAL GAS CRUDE OIL & NGLs --------------------------------------------- ------------------------------------------------ HARDISTY COMPANY COMPANY HEAVY NORTH AVERAGE HENRY HUB HUNTINGDON/ AVERAGE WTI @ 12(DEGREE) EDMONTON SEA PRICE LOUISIANA AECO SUMAS PRICE CUSHING(i) API PAR(ii) BRENT YEAR $CDN/MCF $US/MMBTU $CDN/MMBTU $CDN/MMBTU $CDN/BBL $US/BBL $CDN/BBL $CDN/BBL $US/BBL ---- -------- --------- ---------- ---------- -------- ------- -------- -------- ------- 2004 6.63 5.80 6.88 6.94 31.82 32.56 26.16 40.68 30.14
(i) "WTI @ Cushing" refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma. (ii) "Edmonton Par Price" refers to the price of light gravity (40o API), low sulphur content crude oil at Edmonton, Alberta. (iii) Foreign exchange rate used was $0.77 US / $1.00 Cdn. 10. The forecast price and cost cases assume the continuance of current laws and regulations, and any increases in wellhead selling prices also take inflation into account. Sales prices are based on reference prices as detailed below and adjusted for quality and transporation. Subsequent to 2015, reference prices and costs are escalated at 1.5 per cent per year. Future crude oil, natural gas liquids and natural gas price forecasts were based on Sproule's January 1, 2004 crude oil, natural gas liquids and natural gas pricing model. The crude oil and natural gas forecast prices used in the Evaluation Reports are as follows:
NATURAL GAS CRUDE OIL & NGLs --------------------------------------------- ------------------------------------------------ HARDISTY COMPANY COMPANY HEAVY NORTH AVERAGE HENRY HUB HUNTINGDON/ AVERAGE WTI @ 12(DEGREE) EDMONTON SEA PRICE LOUISIANA AECO SUMAS PRICE CUSHING API PAR BRENT YEAR $CDN/MCF $US/MMBTU $CDN/MMBTU $CDN/MMBTU $CDN/BBL $US/BBL $CDN/BBL $CDN/BBL $US/BBL ---- -------- --------- ---------- ---------- -------- ------- -------- -------- ------- 2004 5.80 5.32 6.04 6.10 29.27 29.63 23.80 37.99 27.63 2005 5.18 4.81 5.36 5.52 26.55 26.80 21.28 34.24 25.27 2006 4.63 4.39 4.80 5.06 25.89 25.76 20.80 32.87 24.21 2007 4.68 4.46 4.91 5.17 26.28 26.14 21.33 33.37 24.57 2008 4.73 4.52 4.98 5.24 26.64 26.53 21.84 33.87 24.94 2009 4.80 4.59 5.05 5.31 26.47 26.93 22.31 34.38 25.32 2010 4.92 4.66 5.14 5.40 26.37 27.34 22.80 34.90 25.70 2011 5.02 4.73 5.24 5.50 26.65 27.75 23.29 35.43 26.08 2012 5.11 4.80 5.33 5.59 26.60 28.16 23.79 35.96 26.47 2013 5.18 4.87 5.43 5.69 26.80 28.58 24.29 36.50 26.87 2014 5.29 4.95 5.52 5.78 27.78 29.01 24.81 37.05 27.27 2015 5.34 5.02 5.62 5.88 28.13 29.45 25.33 37.61 27.68
(i) Foreign exchange rate used was $0.75 US / $1.00 Cdn throughout the forecast 11. Estimated future net revenue from all assets is income derived from the sale of net reserves of crude oil, natural gas and natural gas liquids, less all capital costs, production taxes, and operating costs and before provision for income taxes, administrative overhead costs and existing asset abandonment liabilities. 24 12. The estimated total development capital costs net to the Company necessary to achieve the estimated future net "proved" and "proved and probable" production revenues are:
PROVED PROVED AND PROBABLE ---------------------------------------------------------------------------------------------- FORECAST PRICE CASE CONSTANT PRICE CASE FORECAST PRICE CASE CONSTANT PRICE CASE ($Millions) ($Millions) ($Millions) ($Millions) ------------------- ------------------- ------------------- ------------------- 2004 895 894 1,027 1,026 2005 651 639 986 971 2006 229 221 512 501 2007 197 187 226 219 2008 191 179 323 290 2009 86 78 121 110 2010 60 55 96 88 2011 58 52 166 150 2012 42 37 43 38 2013 28 24 178 156 2014 3 2 3 2 2015 1 1 14 11 Thereafter 181 148 348 286
13 Estimated future net revenue includes the value of the Company's midstream assets which is estimated to be $638.9 million undiscounted and $313.4 million, $243.1 million and $197.3 million discounted at 10%, 15% and 20% respectively. 14. The Evaluation Reports involved data supplied by the Company with respect to quality, heating value and transportation adjustments, interests owned, royalties payable, operating costs and contractual commitments. This data was audited by Sproule against corporate financial statements and was found to have no material differences. No field inspection was conducted. A report on reserves data by Sproule and a report of the Company's management and directors on oil and natural gas disclosure are provided in Schedules A and B, respectively, to this Annual Information Form. The Company does not file estimates of its total oil and natural gas reserves with any U. S. agency or federal authority other than the SEC. 25 C. RECONCILIATION OF CHANGES IN NET RESERVES The following table summarizes the changes during the past year in reserves after deduction of royalties payable to others and using constant prices and costs:
----------------------------------------------- ------------------------------------------------- CRUDE OIL AND NATURAL GAS LIQUIDS (MMBBLS) NATURAL GAS (BCF) OFFSHORE OFFSHORE NORTH NORTH WEST NORTH NORTH WEST AMERICA SEA AFRICA TOTAL AMERICA SEA AFRICA TOTAL ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- PROVED RESERVES Reserves, December 31, 2002 571 202 75 848 2,446 71 71 2,588 Extensions and discoveries 1 -- 13 14 58 -- 6 64 Infill Drilling 54 -- -- 54 243 -- -- 243 Improved Recovery 9 -- -- 9 8 -- -- 8 Property purchases 7 27 -- 34 50 19 -- 69 Property disposals -- -- -- -- (3) -- -- (3) Production (56) (21) (4) (81) (355) (17) (3) (375) Revisions of prior estimates 2 14 1 17 (21) (11) (10) (42) ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------ Reserves, December 31, 2003 588 222 85 895 2,426 62 64 2,552 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- TOTAL PROVED AND PROBABLE RESERVES Reserves, December 31, 2002 636 277 121 1,034 2,765 89 90 2,944 Extensions and discoveries 1 -- 17 18 72 -- 11 83 Infill Drilling 58 -- -- 58 285 -- -- 285 Improved Recovery 25 -- 12 37 26 -- (6) 20 Property purchases 10 33 -- 43 59 22 -- 81 Property disposals -- -- -- -- (3) -- -- (3) Production (56) (21) (4) (81) (355) (17) (3) (375) Revisions of prior estimates 183 28 (13) 198 70 8 (20) 58 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------ Reserves, December 31, 2003 857 317 133 1,307 2,919 102 72 3,093 ----------- ----------- ----------- ----------- ------------ ----------- ----------- ------------
Information on the Company's oil and natural gas reserves is provided in accordance with United States FAS 69, "Disclosures About Oil and Gas Producing Activities" in the Company's 2003 Annual Report under "Supplementary Oil and Gas Information" on pages 82 to 85 and is incorporated herein by reference. 26 D. CRUDE OIL AND NATURAL GAS PRODUCTION The Company's working interest share of oil, NGLs and natural gas production and revenues received for the last three financial years is summarized in the following tables: YEAR ENDED DECEMBER 31 --------------------------------------- 2003 2002 2001 ---- ---- ---- Daily Production Crude Oil and NGLs (bbls/d) 242,392 215,335 206,323 Natural Gas (MMcf/d) 1,298.7 1,232.3 918.1 Annual Production Crude Oil and NGLs (Mbbls) 88,473 78,597 75,308 Natural Gas (Bcf) 474.0 449.8 355.1
NETBACKS INFORMATION BY QUARTER YEAR 2003 YEAR 2002 ----------------------------------------------- ----------------------------------------------- 1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- ------- ------- ------- ------- ----- PRODUCT NETBACKS Crude oil and NGLs ($/bbl) Sales Price $35.26 $30.27 $30.97 $30.02 $31.59 $24.50 $28.27 $33.57 $31.10 $29.76 Royalties $ 3.56 $ 2.78 $ 2.56 $ 2.22 $ 2.77 $ 2.28 $ 3.02 $ 3.56 $ 3.53 $ 3.16 Production Expenses $10.79 $10.80 $10.14 $ 9.45 $10.28 $ 7.81 $ 7.95 $ 8.67 $ 9.10 $ 8.45 NETBACK $20.91 $16.69 $18.27 $18.35 $18.54 $14.41 $17.30 $21.34 $18.47 $18.15 Natural Gas ($/Mcf) Sales Price $7.25 $6.12 $5.50 $5.23 $6.02 $3.06 $3.68 $3.13 $5.00 $3.76 Royalties $1.78 $1.35 $1.11 $1.05 $1.32 $0.55 $0.77 $0.67 $1.09 $0.78 Production Expenses $0.57 $0.59 $0.63 $0.63 $0.60 $0.58 $0.57 $0.55 $0.57 $0.57 NETBACK $4.90 $4.18 $3.76 $3.55 $4.10 $1.93 $2.34 $1.91 $3.34 $2.41 CRUDE OIL AND NGL NETBACKS BY TYPE Light/Pelican Lake/NGLs ($/bbl) Sales Price $41.51 $34.53 $35.75 $36.20 $36.97 $28.58 $31.84 $36.58 $36.38 $33.84 Royalties $ 4.18 $ 3.32 $ 3.11 $ 2.82 $ 3.35 $ 3.25 $ 4.04 $ 4.48 $ 4.39 $ 4.10 Production Expenses $10.42 $ 9.76 $ 9.53 $ 9.65 $ 9.83 $ 7.48 $ 8.36 $10.06 $ 9.38 $ 8.97 NETBACK $26.91 $21.45 $23.11 $23.73 $23.79 $17.85 $19.44 $22.04 $22.61 $20.77 Heavy ($/bbl) Sales Price $26.63 $24.56 $24.46 $22.14 $24.39 $20.01 $24.20 $29.78 $24.54 $24.89 Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00 $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03 Production Expenses $11.30 $12.19 $10.96 $ 9.19 $10.88 $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84 Netback $12.62 $10.31 $11.67 $11.48 $11.51 $10.62 $14.86 $20.45 $13.32 $15.02
NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. 27
NETBACKS INFORMATION BY QUARTER YEAR 2003 YEAR 2002 ----------------------------------------------- ----------------------------------------------- 1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- ------- ------- ------- ------- ----- SEGMENTED NORTH AMERICA PRODUCT NETBACKS Light/Pelican Lake/NGLs ($/bbl) Sales Price $35.08 $32.01 $31.97 $31.64 $32.69 $25.27 $28.90 $32.83 $31.94 $30.01 Royalties $ 7.65 $ 6.33 $ 6.04 $ 5.51 $ 6.39 $ 4.24 $ 5.11 $ 5.98 $ 5.81 $ 5.35 Production Expenses $ 6.09 $ 6.42 $ 6.76 $ 7.24 $ 6.62 $ 5.25 $ 5.30 $ 5.00 $ 5.28 $ 5.20 NETBACK $21.34 $19.26 $19.17 $18.89 $19.68 $15.78 $18.49 $21.85 $20.85 $19.46 Heavy ($/bbl) Sales Price $26.63 $24.56 $24.46 $22.14 $24.39 $20.01 $24.20 $29.78 $24.54 $24.89 Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00 $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03 Production Expenses $11.30 $12.19 $10.96 $ 9.19 $10.88 $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84 NETBACK $12.62 $10.31 $11.67 $11.48 $11.51 $10.62 $14.86 $20.45 $13.32 $15.02 Natural Gas ($/Mcf) Sales Price $7.36 $6.25 $5.62 $5.32 $6.14 $3.05 $3.72 $3.15 $5.04 $3.78 Royalties $1.84 $1.40 $1.16 $1.10 $1.38 $0.57 $0.79 $0.69 $1.11 $0.80 Production Expenses $0.55 $0.56 $0.58 $0.60 $0.57 $0.56 $0.55 $0.52 $0.55 $0.55 NETBACK $4.97 $4.29 $3.88 $3.62 $4.19 $1.92 $2.38 $1.94 $3.38 $2.43 NORTH SEA PRODUCT NETBACKS Light Oil ($/bbl) Sales Price $50.27 $37.83 $39.84 $41.93 $42.43 $33.75 $39.36 $41.68 $41.83 $39.79 Royalties $ 0.11 ($0.19) $ 0.09 ($0.15) ($0.03) $ 1.54 $ 1.76 $ 2.56 $ 2.79 $ 2.30 Production Expenses $15.50 $14.17 $13.25 $13.42 $14.07 $10.09 $15.72 $18.30 $14.68 $15.06 NETBACK $34.66 $23.85 $26.50 $28.66 $28.39 $22.12 $21.88 $20.82 $24.36 $22.43 Natural Gas ($/Mcf) Sales Price $4.03 $2.21 $2.57 $3.32 $3.03 $3.77 $1.80 $1.98 $3.20 $2.75 Royalties -- -- -- -- -- -- -- -- -- -- Production Expenses $1.09 $1.45 $1.60 $1.16 $1.33 $1.33 $1.90 $1.78 $1.25 $1.53 NETBACK $2.94 $0.76 $0.97 $2.16 $1.70 $2.44 ($0.10) $0.20 $1.95 $1.22 OFFSHORE WEST AFRICA PRODUCT NETBACKS Light Oil ($/bbl) Sales Price $37.86 $34.34 $37.37 $36.42 $36.47 $37.61 $33.92 $42.78 $43.15 $40.10 Royalties $1.20 $0.99 $1.13 $1.03 $1.08 $1.65 $1.11 $1.34 $1.35 $1.35 Production Expenses $14.03 $9.32 $7.11 $6.67 $8.68 $18.62 $12.76 $11.23 $13.68 $13.63 NETBACK $22.63 $24.03 $29.13 $28.72 $26.71 $17.34 $20.05 $30.21 $28.12 $25.12 Natural Gas ($/Mcf) Sales Price $3.80 $5.09 $4.59 $3.95 $4.37 -- -- $4.97 $4.63 $4.82 Royalties $0.11 $0.15 $0.14 $0.11 $0.13 -- -- $0.15 $0.15 $0.15 Production Expenses $2.37 $1.45 $1.24 $1.18 $1.39 -- -- $1.77 $1.85 $1.81 NETBACK $1.32 $3.49 $3.21 $2.66 $2.85 $ -- $ -- $3.05 $2.63 $2.86
NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. 28 NETBACKS INFORMATION BY QUARTER
YEAR 2001 --------------------------------------------------------------- 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- AVERAGE DAILY PRODUCTION VOLUMES Crude Oil and NGLs (bbls) 205,588 214,716 207,065 198,000 206,323 Natural Gas (Mcf) 850.8 884.6 923.8 1,011.6 918.1 PRODUCT NETBACKS Crude oil and NGLs ($/bbl) Sales Price $22.06 $25.32 $28.37 $21.28 $24.31 Royalties 2.36 2.42 2.47 1.41 2.17 Production Expenses 8.18 7.57 7.29 7.52 7.64 NETBACK $11.52 $15.33 $18.61 $12.35 $14.50 NATURAL GAS ($/MCF) Sales Price $9.30 $5.93 $3.12 $2.94 $5.16 Royalties 2.40 1.47 0.67 0.62 1.25 Production Expenses 0.50 0.50 0.50 0.53 0.51 NETBACK $6.40 $3.96 $1.95 $1.79 $3.40 CRUDE OIL AND NGL NETBACKS BY TYPE Light/Pelican Lake/NGLs ($/bbl) Sales Price $30.96 $33.59 $32.75 $26.95 $31.13 Royalties 4.03 3.86 3.30 2.29 3.38 Production Expenses 5.99 6.10 6.12 7.15 6.34 NETBACK $20.94 $23.63 $23.33 $17.51 $21.41 HEAVY ($/BBL) Sales Price $12.76 $15.83 $23.21 $14.85 $16.63 Royalties 0.61 0.77 1.50 0.43 0.83 Production Expenses 10.48 9.24 8.68 7.93 9.10 Netback $1.67 $5.82 $13.03 $6.49 $6.70 NOTE: Pelican Lake oil has an API of 14(0)to 17(0), but receives medium quality crude netbacks due to exceptionally low operating costs and low royalty rates. SEGMENTED NORTH AMERICA PRODUCT NETBACKS YEAR 2001 --------------------------------------------------------------- 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- Light/Pelican Lake/NGLs ($/bbl) Sales Price $27.04 $27.49 $29.95 $23.83 $27.10 Royalties 4.57 5.04 4.17 2.79 4.16 Production Expenses 3.84 4.02 4.22 4.74 4.19 NETBACK $18.63 $18.43 $21.56 $16.30 $18.75 Heavy ($/bbl) Sales Price $12.76 $15.83 $23.21 $14.85 $16.63 Royalties 0.61 0.77 1.50 0.43 0.83 Production Expenses 10.48 9.24 8.68 7.93 9.10 NETBACK $1.67 $5.82 $13.03 $6.49 $6.70 Natural Gas ($/Mcf) Sales Price $9.30 $5.99 $3.13 $2.94 $5.19 Royalties 2.40 1.49 0.68 0.63 1.26 Production Expenses 0.50 0.50 0.50 0.52 0.50 NETBACK $6.40 $4.00 $1.95 $1.79 $3.43 NORTH SEA PRODUCT NETBACKS Light Oil ($/bbl) Sales Price $41.04 $43.07 $37.28 $33.39 $38.66 Royalties $2.86 $2.23 $1.97 $1.52 $2.10 Production Expenses $9.22 $8.42 $8.09 $10.54 $9.00 NETBACK $28.96 $32.42 $27.22 $21.33 $27.56 Natural Gas ($/Mcf) Sales Price $ -- $ 1.74 $ 2.51 $ 3.00 $ 2.51 Royalties $ -- $ -- $ -- $ -- $ -- Production Expenses $ -- $ 0.61 $ 0.74 $ 1.34 $ 0.94 NETBACK $ -- $ 1.13 $ 1.77 $ 1.66 $ 1.57
29 OFFSHORE WEST AFRICA PRODUCT NETBACKS
YEAR 2001 --------------------------------------------------------------- 1ST 2ND 3RD 4TH YEAR QUARTER QUARTER QUARTER QUARTER ENDED ------- ------- ------- ------- ----- Light Oil ($/bbl) Sales Price $40.58 $39.75 $34.66 $19.56 $33.57 Royalties $ -- $ 0.65 $ 2.03 $ 0.64 $ 0.93 Production Expenses $38.80 $17.23 $19.05 $19.15 $21.77 NETBACK $ 1.78 $21.87 $13.58 $(0.23) $10.87 Natural Gas ($/Mcf) Sales Price -- -- -- -- -- Royalties -- -- -- -- -- Production Expenses -- -- -- -- -- NETBACK $ -- $ -- $ -- $ -- $ --
E. HISTORICAL DRILLING ACTIVITY BY PRODUCT The following table sets forth the gross and net wells in which the Company has participated for the period indicated: YEAR ENDED DECEMBER 31 --------------------------------------------------- 2003 2002 ------------------------ ------------------------ GROSS NET GROSS NET ----- --- ----- --- Natural Gas 841 777 183 162 Crude Oil 490 458 316 264 Service/Stratigraphic 447 440 456 447 Dry Holes 126 118 32 27 ------------------------ ------------------------ Total 1,904 1,793 987 900 ======================== ======================== *Total Success Rate 91% 94% *excluding service and stratigraphic test wells 30 F. CAPITAL EXPENDITURES Costs incurred by the Company in respect of its programs of acquisition and disposition, and exploration and development of crude oil and natural gas properties, are summarized in the following tables: YEAR ENDED DECEMBER 31 ------------------------------------- 2003 2002 ---------------- --------------- Corporate acquisition -- 2,393 Net property acquisitions 336 440 Land acquisition and retention 154 114 Seismic evaluation 77 63 Well drilling, completion and equipping 1,194 626 Pipeline and production facilities 522 292 ---------------- --------------- Reserve replacement expenditures 2,283 3,928 Midstream operations 11 20 Horizon Project 152 68 Abandonments 40 43 Head office equipment 20 10 ---------------- --------------- Total Net Capital Expenditures 2,506 4,069 ================ =============== 31
2003 THREE MONTHS ENDED --------------------------------------------------------------------- ($ Millions) CAPITAL EXPENDITURES BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ------- ------- -------- ------- Corporate acquisition -- -- -- -- Net property acquisitions 178 23 106 29 Land acquisition and retention 21 36 53 44 Seismic evaluation 19 21 12 25 Well drilling, completion and equipping 396 190 256 352 Pipeline and production facilities 149 107 133 133 ------- ------- -------- ------- Reserve replacement expenditures 763 377 560 583 Midstream operations 3 1 5 2 Horizon Project 41 27 32 52 Abandonments 3 3 14 20 Head office equipment 3 2 10 5 ------- ------- -------- ------- Total Net Capital Expenditures 813 410 621 662 ===================================================================== 2002 THREE MONTHS ENDED --------------------------------------------------------------------- ($ Millions) CAPITAL EXPENDITURES BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ------- ------- -------- ------- Corporate acquisition -- -- 2,393 -- Net property acquisitions 35 33 333 39 Land acquisition and retention 28 19 48 18 Seismic evaluation 25 14 5 19 Well drilling, completion and equipping 207 136 144 139 Pipeline and production facilities 124 67 56 45 ------- ------- -------- ------- Reserve replacement expenditures 419 269 2,979 260 Midstream operations 10 5 -- 6 Horizon Project 22 17 10 19 Abandonments 7 12 20 4 Head office equipment 1 2 4 3 ------- ------- -------- ------- Total Net Capital Expenditures 459 305 3,013 292 =====================================================================
32 G. NON-RESERVE ACREAGE The following table summarizes the Company's working interest holdings in core area non-reserve acreage as at December 31, 2003: GROSS ACRES NET ACRES ----------- --------- (thousands) (thousands) NORTH AMERICA Alberta 9,304 7,859 British Columbia 2,011 1,560 Saskatchewan 449 380 Manitoba 12 12 NORTH SEA United Kingdom 804 573 France 2,693 1,347 OFFSHORE WEST AFRICA Angola 1,220 610 Cote d'Ivoire 452 333 5,550 5,550 South Africa --------------- -------------- Total 22,495 18,224 =============== ============== H. DEVELOPED ACREAGE The following table summarizes the Company's working interest holdings in core region developed acreage as at December 31, 2003: GROSS ACRES NET ACRES ----------- --------- (thousands) (thousands) NORTH AMERICA Alberta 4,361 3,415 British Columbia 605 461 Saskatchewan 295 156 Manitoba 5 4 NORTH SEA United Kingdom 106 65 France -- -- OFFSHORE WEST AFRICA Angola -- -- Cote d'Ivoire 8 5 South Africa -- -- --------------- -------------- Total 5,380 4,106 =============== ============== 33 SELECTED FINANCIAL INFORMATION The following table summarizes the consolidated financial statements of the Company, which follows the full cost method of accounting for crude oil and natural gas operations:
----------------------------------------- YEAR ENDED DECEMBER 31 ----------------------------------------- 2003 2002 ---- ---- ($ millions, except per share information) Revenues (1) (net of royalties) 5,100 3,742 Cash flow from operations attributable to common shareholders 3,160 2,254 Per common share - basic 23.54 17.63 - diluted 23.06 16.99 Net earnings attributable to common shareholders 1,407 570 Per common share - basic 10.48 4.46 - diluted 10.14 4.31 Total assets 14,198 13,359 Total long-term debt(2) 2,645 4,074
--------------------------------------------------------------------------------- 2003 THREE MONTHS ENDED --------------------------------------------------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- ($ millions, except per share information) Revenues (1) (net of royalties) 1,407 1,254 1,244 1,195 Net earnings attributable to 428 525 203 251 common shareholders Per common share - basic 3.19 3.91 1.51 1.87 - diluted 3.03 3.78 1.49 1.83 --------------------------------------------------------------------------------- 2002 THREE MONTHS ENDED --------------------------------------------------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- ------- -------- ------- ($ millions, except per share information) Revenues (1) (net of royalties) 690 797 1,072 1,183 Net earnings attributable to 99 145 117 209 common shareholders Per common share - basic 0.81 1.18 0.88 1.56 - diluted 0.79 1.09 0.86 1.51
(1) Restated to exclude transportation costs from revenue. (2) Excluding current portion of ling-term debt. 34 MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES The Company's common shares are listed and posted for trading on Toronto Stock Exchange and the New York Stock Exchange under the symbol CNQ. On January 17, 2001, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, beginning January 22, 2001 and ending January 21, 2002, to purchase for cancellation up to 6,114,726 common shares of the Company, being 5 per cent of the 122,294,533 common shares of the Company outstanding on January 17, 2001. During this period, 2,537,800 common shares were purchased for cancellation at an average price of $44.61. On January 21, 2002, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, beginning January 23, 2002 and ending January 22, 2003, to purchase for cancellation up to 6,060,180 common shares of the Company, being 5 per cent of the 121,203,603 common shares of the Company outstanding on January 18, 2002. No common shares were purchased during this program. In January 2002, the Company issued 60,000 flow-through common shares at a price of $39.00 per common share. The value of the common shares was determined as the closing market price on Toronto Stock Exchange on the day prior to the allotment of the common shares. On January 22, 2003, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, beginning January 24, 2003 and ending January 23, 2004, to purchase for cancellation up to 6,692,799 common shares of the Company, being 5 per cent of the 133,855,988 common shares of the Company outstanding on January 17, 2003. Under this program, the Company purchased a total of 2,734,800 common shares for cancellation at an average purchase price of $52.51 for each common share purchased. On January 22, 2004, the Company announced its intention to make a Normal Course Issuer Bid through the facilities of Toronto Stock Exchange and the New York Stock Exchange, commencing January 24, 2004 and ending January 23, 2005, to purchase for cancellation up to 6,690,385 common shares of the Company, being 5 per cent of the 133,807,695 common shares of the Company outstanding on January 13, 2004. On February 19, 2004, the Board of Directors passed a resolution proposing an amendment to the Articles of the Company to split the issued and outstanding Common Shares of the Company on a two-for-one basis subject to shareholder approval at the Annual and Special Meeting of Shareholders scheduled for May 6, 2004. DIVIDEND HISTORY The dividend policy of the Company undergoes a periodic review by the Board of Directors and is subject to change at any time depending upon the earnings of the Company, its financial requirements and other factors existing at the time. Prior to 2001, dividends had not been paid on the common shares of the Company. On January 17, 2001 the Board of Directors approved a dividend policy for the payment of a regular quarterly dividend of $0.10 per common share. On February 25, 2002 the Board of Directors approved an increase in the quarterly dividend to $0.125 per common share commencing with the dividend payable April 1, 2002. On February 35 20, 2003 the Board of Directors approved a further increase in the quarterly dividend to $0.15 per common share commencing with the dividend payable April 1, 2003. The Board of Directors reviewed the dividend payments for 2004 and on February 19, 2004 the Board of Directors approved a 33 per cent increase in the quarterly dividend to $0.20 per common share commencing with the dividend payable April 1, 2004. Dividends have been paid on the first day of January, April, July and October of each year since 2001. DIRECTORS AND OFFICERS The names, municipalities of residence, offices held with the Company and principal occupations of the directors and officers of the Company are set forth below:
POSITION PRINCIPAL PRESENTLY OCCUPATION NAME HELD DURING PAST 5 YEARS Catherine M. Best Director(2) Senior Vice-President, Risk Management and Chief Financial Calgary, Alberta (age 50) Officer of the Calgary Health Region from 2002 to present, Vice-President, Corporate Services and Chief Financial Officer of the Calgary Health Region from February 2000 to 2002; prior thereto with Ernst & Young since 1980, most recently as a Corporate Audit Partner from 1991 to 2000. Has served continuously as a director since November 2003. N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (a private Calgary, Alberta Director(3)(5) management and consulting company). Has served (age 44) continuously as a director of the Company since September 1988. Currently serving on the board of directors of Ensign Resource Service Group Inc.; Magellan Aerospace Corporation; and, Penn West Petroleum Ltd. Ambassador Gordon D. Giffin Director(1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm) Atlanta, Georgia (age 54) since May 2001; prior thereto United States Ambassador to Canada. Has served continuously as a director of the Company since May 2002. Currently serving on the board of directors of Bowater, Inc.; Canadian National Railway; Canadian Imperial Bank of Commerce; and, Transalta Corporation. James T. Grenon Director(2)(4) Managing Director, TOM Capital Associates Inc. (a private Calgary, Alberta (age 47) investment company). Has served continuously as a director of the Company since September 1988. Currently serving on the board of trustees for Foremost Industries Income Fund. John G. Langille President and Director Officer of the Company. Has served continuously as a Calgary, Alberta (age 58) director of the Company since June 1982. Keith A.J. MacPhail Director(3)(5) Chairman, President and Chief Executive Officer, Bonavista Calgary, Alberta (age 47) Petroleum Ltd. (independent oil and natural gas company) since November 1997 and Chairman, NuVista Energy Ltd since July 2003. Has served continuously as a director of the Company since October 1993. Currently serving on the board of directors of Bonavista Petroleum Ltd., Bonavista Energy Trust and NuVista Energy Ltd. Allan P. Markin Chairman and Director Chairman of the Company. Has served continuously as a Calgary, Alberta (age 58) director of the Company since January 1989. James S. Palmer, C.M., A. O. Director(1)(2)(3)(4) Chairman, Burnet, Duckworth & Palmer LLP (law firm). Has E., Q.C. (age 75) served continuously as a director of the Company since May Calgary, Alberta 1997. Currently serving on the board of directors of Magellan Aerospace Corporation; Trenton Iron Works; Rally Energy Corp.; and, on the board of trustees for Rogers Sugar Income Fund.
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POSITION PRINCIPAL PRESENTLY OCCUPATION NAME HELD DURING PAST 5 YEARS Dr. Eldon R. Smith, M.D. Director(4)(5) Professor and Former Dean, Faculty of Medicine, The Calgary, Alberta (age 64) University of Calgary. Has served continuously as a director of the Company since May 1997. Currently serving on the board of directors of Vasogen Inc.; Pheromone Sciences Corp.; and, Biomax Technologies Inc. David A. Tuer Director(1)(3) President and CEO of Hawker Resources Inc. (independent Calgary, Alberta (age 54) oil and natural gas company) since January 2003 and Chairman, Calgary Health Region since October 2001. Prior thereto President and Chief Executive Officer, PanCanadian Energy Corporation. Has served continuously as a director of the Company since May 2002. Currently serving on the board of directors of Hawker Resources Inc.; Rockwater Capital Corporation; Ultima Energy Trust; and, Argo Energy Ltd Steve W. Laut Chief Operating Officer Officer of the Company Calgary, Alberta (age 46) Real M. Cusson Senior Vice-President, Officer of the Company Calgary, Alberta Marketing (age 53) Real J. H. Doucet Senior Vice-President, Officer of the Company since October 2000; prior thereto Calgary, Alberta Oil Sands director of various divisions at Suncor Inc. since 1993. (age 51) Allen M. Knight Senior Vice-President, Officer of the Company Calgary, Alberta International & Corporate Development (age 54) Tim S. McKay Senior Vice-President, Officer of the Company Calgary, Alberta Operations (age 42) Douglas A. Proll Senior Vice-President, Officer of the Company since April 2001; prior thereto Calgary, Alberta Finance Vice President Finance and Treasurer of Renaissance Energy (age 53) Ltd. until August 2000 and most recently Vice President Finance and Business Development of Husky Energy Inc. from August 2000 to February 2001. Lyle G. Stevens SeniorVice-President, Officer of the Company Calgary, Alberta Exploitation (age 49) Mary-Jo Case Vice-President, Land Officer of the Company since May 2002; prior thereto Calgary, Alberta (age 45) Co-ordinator Land at PanCanadian Petroleum Limited 1994 to 1999 and most recently Manager Commercial Ventures and Land at PanCanadian Petroleum Limited 1999 to 2002. William R. Clapperton Vice-President, Officer of the Company since January 2002; prior thereto Calgary, Alberta Regulatory, Stakeholder Manager, Surface Land and Environment for the Company. and Environmental Affairs (age 41) Gordon M. Coveney Vice-President, Officer of the Company since September 2003; prior thereto Calgary, Alberta Exploration, Northeast Exploration Manager for the Company. District (age 50) Cameron S. Kramer Vice-President, Officer of the Company since September 2002; prior thereto Calgary, Alberta Field Operations Production Engineer of the Company until March 2000 and (age 36) most recently Manager, Field Operations of the Company from April 2000 to September 2002.
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POSITION PRINCIPAL PRESENTLY OCCUPATION NAME HELD DURING PAST 5 YEARS Leon Miura Vice-President, Upgrading Officer of the Company since August 2003; prior thereto Calgary, Alberta (age 49) from 1978 to 2003 held progressively senior positions at Petroleos de Venezuela including Cerro Negro Execution Manager, Heavy Oil Upgrading from 1997 to 2001 and most recently Nitrogen Injection Project Director, Secondary Recovery at Petroleos de Venezuela 2002 to 2003. J. Kevin Stromquist Vice-President, Officer of the Company since September 2003, prior thereto Calgary, Alberta Exploration, Northwest Exploration Manager for the Company. Alberta (age 44) Jeffrey W. Wilson Vice-President, Officer of the Company since September 2003; prior thereto Calgary, Alberta Exploration, B. C./S. Exploration Manager for the Company. AB. Districts (age 51) Lynn M. Zeidler Vice-President, Bitumen Officer of the Company since August 2003; prior thereto Calgary, Alberta Production from May 1980 to July 2003 held progressively senior (age 47) positions at Shell Canada Limited including on secondment from Shell Canada Limited as Manager-Tier 1 Implementation at Sable Offshore Energy Inc January 1998 to September 2000 and most recently General Project Manager, Athahasca Oil Sands Project at Shell Canada Limited October 2000 to May 2003 and concurrently as Vice President & Project Director, Muskeg River Mine at Albian Sands Energy Inc. May 2002 to July 2003 and General Manager Claims Athabasca Oil Sands Project at Shell Canada Limited May 2003 to July 2003. Bruce E. McGrath Corporate Secretary Officer of the Company Calgary, Alberta (age 54)
(1) Member of the Nominating and Corporate Governance Committee (2) Member of the Audit Committee (3) Member of the Reserves Committee (4) Member of the Compensation Committee (5) Member of the Safety, Health and Environmental Committee All directors stand for election at each Annual General Meeting of CNRL shareholders. With the exception of Ms. C. M. Best who was appointed to the Board effective November 17, 2003, all of the current directors were elected to the Board at the last annual meeting of shareholders held on May 8, 2003. All of the current directors are standing for election at the Annual and Special Meeting of Shareholders scheduled for May 6, 2004. There are potential conflicts of interest to which the directors and officers of the Company may become subject in connection with the operations of the Company. Some of the directors and officers have been and will continue to be engaged in the identification and evaluation of businesses and assets with a view to potential acquisition of interests on their own behalf and on behalf of other corporations, and situations may arise where the directors and officers will be in direct competition with the Company. Conflicts, if any, will be subject to the procedures and remedies under the BUSINESS CORPORATIONS ACT (Alberta). As at December 31, 2003, the directors and officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, in the aggregate, approximately 5 per cent of the total outstanding common shares (approximately 6 per cent after the exercise of options held by them pursuant to the Company's stock option plan). 38 ADDITIONAL INFORMATION Additional information including Directors' and Executive Officers' remuneration, principal holders of the Company's securities, options to purchase the Company's securities and interest of insiders in material transactions is contained in the Company's Notice of Annual and Special Meeting and Information Circular dated March 25, 2004 in connection with the Annual and Special Meeting of Shareholders of CNRL to be held on May 6, 2004 which information is incorporated herein by reference. Additional financial information and discussion of the affairs of the Company and the business environment in which the Company operates is provided in the Company's Management Discussion and Analysis, comparative Consolidated Financial Statements and Supplementary Oil & Gas Information for the most recently completed fiscal year ended December 31, 2003 found on pages 38 to 59, 60 to 81 and 82 to 85 respectively, of the 2003 Annual Report to the Shareholders, which information is incorporated herein by reference. The Company shall provide to any person, upon request to the Corporate Secretary of the Company: (a) when securities of the Company are in the course of distribution pursuant to a short form prospectus or a preliminary short form prospectus has been filed in respect of a distribution of its securities, (i) one copy of the Annual Information Form of the Company, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form, (ii) one copy of the comparative consolidated financial statements of the Company for its most recently completed financial year together with the accompanying report of the auditor and one copy of any interim consolidated financial statements of the issuer subsequent to the consolidated financial statements for its most recently completed financial year, (iii) one copy of the information circular of the Company in respect of its most recent annual meeting of shareholders that involved the election of directors or one copy of any annual filing prepared in lieu of that information circular, as appropriate, and (iv) one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and are not required to be provided under (i) to (iii) above; or (b) at any other time, one copy of any other documents referred to in (a)(i), (ii) and (iii) above, provided the Company may require the payment of a reasonable charge if a person who is not a security holder of the issuer makes the request. 39 For additional copies of this Annual Information Form and the materials listed in the preceding paragraphs, please contact: Corporate Secretary of the Corporation at: 2500, 855 - 2nd Street S.W. Calgary, Alberta T2P 4J8 40 SCHEDULE "A" AMENDED FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR REPORT ON RESERVES DATA To the Board of Directors of Canadian Natural Resources Limited (the "Corporation"): 1. We have evaluated the Corporation's reserves data as at December 31, 2003. The reserves data consist of the following: (a) (i) proved oil and natural gas reserves quantities estimated as at December 31, 2003 using constant prices and costs; (ii) the related estimated future net revenue; and (iii) the related standardized measure calculation for proved oil and natural gas reserves quantities. (b) (i) proved and proved plus probable oil and natural gas reserves estimated as at December 31, 2003 using forecast prices and costs; and (ii) the related estimated future net revenue. 2. The reserves data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data based on our evaluation. 3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) with the necessary modifications to reflect definitions and standards under the U.S. Financial Accounting Standards Board policies (the "FASB Standards") and the legal requirements of the U.S. Securities and Exchange Commission ("SEC Requirements"). 4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions as outlined above. 41 5. The following table sets forth the estimated net present value of future cash flows (before deduction of income taxes) attributed to proved oil and gas reserves quantities, estimated using constant prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have evaluated and reported on to the Corporation's management and board of directors:
-------------------------------------------------------------------------------------------------------------------- INDEPENDENT DESCRIPTION LOCATION OF RESERVES QUALIFIED AND (COUNTRY OR FOREIGN RESERVES PREPARATION GEOGRAPHIC AREA) NET PRESENT VALUES OF FUTURE CASH FLOWS EVALUATOR OR DATE OF AUDITOR EVALUATION (BEFORE INCOME TAXES, 10% DISCOUNT RATE) REPORT -------------------------------------------------------------------------------------------------------------------- AUDITED EVALUATED REVIEWED TOTAL MM$ MM$ MM$ MM$ -------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------- Sproule Sproule North America United 0 $13,015.6 $0 $13,015.6 Evaluated the Kingdom, West Africa 0 $ 2,086.9 $0 $ 2,086.9 P&NG Reserves 0 $ 1,014.9 $0 $ 1,014.9 of CNRL (As of January 1, 2004) -------------------------------------------------------------------------------------------------------------------- TOTALS $0 $16,117.4 $0 $16,117.4 --------------------------------------------------------------------------------------------------------------------
6. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook as modified by the FASB Standards and SEC requirements. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. 7. We have no responsibility to update our evaluation for events and circumstances occurring after their respective preparation dates. 42 8. Reserves are estimates only, and not exact quantities. In addition, as the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. Executed as to our report referred to above: February 18, 2004 SPROULE ASSOCIATES LIMITED ORIGINAL SIGNED BY: /s/ Harry J. Helwerda ------------------------------ Harry J. Helwerda, P.Eng., Vice-President, Engineering, Canada and U.S. ORIGINAL SIGNED BY: /s/ R. Keith MacLeod ------------------------------ R. Keith MacLeod, P.Eng. Executive Vice-President ORIGINAL SIGNED BY: /s/ Doug Ho ------------------------------ Doug Ho, P.Eng. Manager, Engineering, and Associate ORIGINAL SIGNED BY: /s/ Ken H. Crowther ------------------------------ Ken H. Crowther, P.Eng. President 43 SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION Management of Canadian Natural Resources Limited (the "Corporation") is responsible for the preparation and disclosure of information with respect to the Corporation's oil and natural gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following: (a) (i) proved oil and natural gas reserve quantities estimated as at December 31, 2003 using constant prices and costs; (ii) the related estimated future net revenue; and (iii) the related standardized measure calculation for proved oil and natural gas reserve quantities. (b) (i) proved and proved plus probable oil and natural gas reserves estimated as at December 31, 2003 using forecast prices and costs; and (ii) the related estimated future net revenue Sproule Associates Limited, an independent qualified reserves evaluator has evaluated the Corporation's reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report. The reserves committee (the "Reserves Committee") of the board of directors (the "Board of Directors") of the Corporation has: (a) reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator; (b) met with the independent qualified reserves evaluator to determine whether any restrictions placed by management affected the ability of the independent qualified reserves evaluator to report without reservation; and (c) reviewed the reserves data with management and the independent qualified reserves evaluator. The Reserves Committee of the Board of Directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and natural gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved: (a) the content and filing with securities regulatory authorities of the reserves data and other oil and natural gas information; 44 (b) the filing of the report of the independent qualified reserves evaluator on the reserves data; and (c) the content and filing of this report. Reserves data are estimates only, and are not exact quantities. In addition, as the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. "Signed" Douglas A. Proll Senior Vice President, Finance "Signed" Steve W. Laut Chief Operating Officer "Signed" David A. Tuer Independent Director, and Chairman of the Reserve Committee "Signed" Keith A.J. MacPhail Independent Director, and Member of the Reserve Committee Dated this 19th day of February, 2004 Calgary, Alberta