-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PcHWpv1EQK+f0p16rweR04o+T8UOE5aLSJMm76fXyV+lz+zrpOIPlGv9tAGx3ftZ oojMJ2cnhnaL39twj9YbOQ== 0000912057-02-013048.txt : 20020415 0000912057-02-013048.hdr.sgml : 20020415 ACCESSION NUMBER: 0000912057-02-013048 CONFORMED SUBMISSION TYPE: 6-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020401 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SUNCOR ENERGY INC CENTRAL INDEX KEY: 0000311337 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 000000000 STATE OF INCORPORATION: A0 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 6-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-12384 FILM NUMBER: 02597778 BUSINESS ADDRESS: STREET 1: 112 4TH AVENUE SW PO BOX 38 STREET 2: CALGARY CITY: ALBERTA CANADA STATE: A0 ZIP: T2P 2V5 BUSINESS PHONE: 4032698100 MAIL ADDRESS: STREET 1: 112 FOURTH AVE SW BOX 38 STREET 2: CALGARY CITY: ALBERTA CANADA ZIP: T2P 2V5 FORMER COMPANY: FORMER CONFORMED NAME: SUNCOR INC DATE OF NAME CHANGE: 19970430 FORMER COMPANY: FORMER CONFORMED NAME: GREAT CANADIAN OIL SANDS & SUN OIL CO LTD DATE OF NAME CHANGE: 19791129 6-K 1 a2075015z6-k.txt FORM 6-K COVER, AIF (49 PP), SIGNATURES, EXH.INDEX FORM 6-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Report of Foreign Private Issuer Pursuant to Rule 13a - 16 or 15d - 16 of the Securities Exchange Act of 1934 For the month of: March 2002 Commission File Number: 1-12384 SUNCOR ENERGY INC. (Name of registrant) 112 FOURTH AVENUE S.W. P.O. BOX 38 CALGARY, ALBERTA, CANADA, T2P 2V5 Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F: Form 20-F Form 40-F X --------- --------- Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the SEC pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934: Yes No X --------- --------- If "Yes" is marked, indicate the number assigned to the registrant in connection with Rule 12g3-2(b): N/A SUNCOR ENERGY INC. ANNUAL INFORMATION FORM FEBRUARY 28, 2002 ANNUAL INFORMATION FORM TABLE OF CONTENTS
ANNUAL INFORMATION FORM..................................................................ii GLOSSARY OF TERMS.......................................................................iii CONVERSION TABLE........................................................................vii CURRENCY................................................................................vii FORWARD-LOOKING STATEMENTS..............................................................vii CORPORATE STRUCTURE.......................................................................1 Incorporation of the Issuer..........................................................1 Subsidiaries of Suncor...............................................................1 GENERAL DEVELOPMENT OF THE BUSINESS.......................................................1 Three-Year Highlights................................................................2 NARRATIVE DESCRIPTION OF THE BUSINESS.....................................................5 OIL SANDS..............................................................................5 Operations...........................................................................5 Leasehold Interests and Royalties....................................................7 Estimated Reserves...................................................................8 Reserves Reconciliation.............................................................10 Revenues from Synthetic Crude Oil and Diesel........................................10 Capital Expenditures................................................................11 Environmental Compliance............................................................12 NATURAL GAS...........................................................................12 Reserves and Reserves Reconciliation................................................12 Conventional Crude Oil..............................................................14 Before Royalties at.................................................................15 Natural Gas.........................................................................17 Land Holdings.......................................................................17 Drilling............................................................................18 Wells...............................................................................19 Sales and Sales Revenues............................................................19 Production Costs....................................................................20 Quarterly Volumes and Netback Analysis..............................................21 Marketing, Pipeline and Other Operations............................................22 Capital and Exploration Expenditures................................................22 Environmental Compliance............................................................23 SUNOCO...................................................................................23 Procurement of Feedstocks...........................................................23 Refining Operations.................................................................24 Principal Products..................................................................24 Transportation and Distribution.....................................................26 Capital Expenditures................................................................26 SUNCOR EMPLOYEES.........................................................................27 RISK/SUCCESS FACTORS.....................................................................27 SELECTED CONSOLIDATED FINANCIAL INFORMATION..............................................34 Selected Consolidated Financial Information.........................................34 Dividend Policy and Record..........................................................34 Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas....35 MANAGEMENT'S DISCUSSION AND ANALYSIS.....................................................36 MARKET FOR THE SECURITIES OF THE ISSUER..................................................36 DIRECTORS AND OFFICERS...................................................................37 ADDITIONAL INFORMATION...................................................................40
ii GLOSSARY OF TERMS BITUMEN/HEAVY OIL A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons heavier than pentane, that is not recoverable at a commercial rate in its naturally occurring viscous state through a well without using enhanced recovery methods. When extracted bitumen/heavy oil can be upgraded into crude oil and other petroleum products. CAPACITY Maximum output that can be achieved from a facility in ideal operating conditions in accordance with current design specifications. COALBED METHANE Natural gas produced from wells drilled into a coal formation. Also called coal seam methane. CONVENTIONAL CRUDE OIL Crude oil produced through wells by standard industry recovery methods for the production of crude oil. CONVENTIONAL NATURAL GAS Natural gas produced from all geological strata, excluding coalbed methane. CRUDE OIL Unrefined liquid hydrocarbons, excluding natural gas liquids. DOWNSTREAM This business segment manufactures, distributes and markets refined products from crude oil. DRY HOLE/WELL An exploration or development well determined, on an economic basis, to be incapable of producing hydrocarbons that will be plugged, abandoned and reclaimed. GROSS PRODUCTION/RESERVES Suncor's undivided percentage interest in production/reserves before deducting Crown royalties, freehold and overriding royalty interests. GROSS WELLS/LAND HOLDINGS Total number of wells or acres, as the case may be, in which Suncor has an interest. HEAVY FUEL OIL Residue from refining of conventional crude oil that remains after lighter products such as gasoline, petrochemicals and heating oils have been extracted. iii IN-SITU OIL In-situ or "in place" refers to methods of extracting heavy crude oil from deep deposits of oil sands with minimal disturbance of the ground cover. NATURAL GAS Hydrocarbons that at atmospheric conditions of temperature and pressure are in a gaseous state. NATURAL GAS LIQUIDS Hydrocarbon products recovered as liquids from raw natural gas by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and pentane plus, or a combination thereof. NET PRODUCTION/RESERVES Suncor's undivided percentage interest in total production or total reserves, as the case may be, after deducting Crown royalties and freehold and overriding royalty interests. NET WELLS/LAND HOLDINGS Suncor's undivided percentage interest in the gross number of wells or gross number of acres, as the case may be, after deducting interests of third parties. OVERBURDEN Material overlying oil sands that must be removed before mining. Consists of muskeg, glacial deposits and sand. PROBABLE RESERVES Those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above proved estimates that can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. PROVED RESERVES Those reserves estimated as recoverable with a high degree of certainty under current technology and existing economic conditions, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. RESOURCES Resources, with respect to Suncor's oil sands leases, include quantities of oil and gas that are estimated, on a given date, to be potentially recoverable from known accumulations and undiscovered accumulations that are not proved or probable reserves and are of a higher risk than, and are generally believed to be less likely to be recovered than proved and probable reserves, and also include proved and probable reserves. Total resources include both synthetic crude oil estimates for mining leases, and bitumen estimates for in-situ oil sands leases. iv RESERVOIR Body of porous rock containing an accumulation of water, crude oil or natural gas. SOUR SYNTHETIC CRUDE OIL Crude oil produced from oil sands that requires only partial upgrading and contains a higher sulphur content than sweet synthetic crude oil. SWEET SYNTHETIC CRUDE OIL Crude oil produced from oil sands consisting of a blend of hydrocarbons resulting from thermal cracking and purifying of bitumen. SYNTHETIC CRUDE OIL Upgraded or partially upgraded crude oil recovered from oil sands including surface mineable oil sands leases and in-situ heavy oil leases. UNDEVELOPED OIL AND NATURAL GAS LANDS Suncor's undivided percentage interest in lands where no producing or commercially producible well has been drilled. UPSTREAM This business segment includes acquisition, exploration, development, production and marketing of crude oil, natural gas and natural gas liquids; and for greater clarity includes the production of synthetic crude oil, butimen and other oil products from oil sands. UTILIZATION The average use of capacity taking into consideration planned and unplanned outages and maintenance. WELLS Development Well A crude oil or natural gas well in a reservoir known to be productive and expected to produce in future. DRILLED WELL A well that has been drilled and has a defined status e.g. gas well, shut-in well, producing oil well, producing gas well, suspended well or dry and abandoned well. EXPLORATORY WELL A well drilled in unproved or semi-proved territory with the intention to discover commercial reservoirs or deposits of crude oil and/or natural gas. v ACCOUNTING TERMS BARREL OF OIL EQUIVALENT (BOE) Suncor converts natural gas to crude oil on the approximate long-term economic equivalent basis that 6,000 cubic feet of natural gas equals one barrel of crude oil. DEVELOPMENT COSTS Includes all costs associated with moving reserves from other classes such as "proved undeveloped" and "probable" to the "proved developed" class. FINDING COSTS Includes the cost of and investment in undeveloped land, geological and geophysical activities, exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas reserves. INTEREST COVERAGE -- CASH FLOW BASIS Cash provided from operating activities before interest expense and income tax payments, divided by the aggregate of interest expense and interest capitalized. LIFTING COSTS Includes all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems. MMCF/E (MILLION CUBIC FEET EQUIVALENT) Converts crude oil to natural gas on the approximate long-term economic equivalent basis that one barrel of crude oil equals 6,000 cubic feet natural gas. NET DEBT Long-term borrowings (including the current portion) plus short-term borrowings, less cash and cash equivalents. OPERATING WORKING CAPITAL Current assets (excluding cash and cash equivalents), less current liabilities (excluding borrowings). RETURN ON AVERAGE CAPITAL EMPLOYED Earnings before long-term interest expense as a percentage of average capital employed. Average capital employed is the total of shareholders' equity and debt (short-term borrowings and current and long-term portions of long-term borrowings, less the capitalized cost related to major growth projects in progress), at the beginning and end of the year, divided by two. RETURN ON AVERAGE SHAREHOLDERS' EQUITY Earnings as a percentage of average shareholders' equity. Average shareholders' equity is the aggregate of total shareholders' equity at the beginning and end of the year, divided by two. vi CONVERSION TABLE
1 cubic metre m(3) = 6.29 barrels 1 tonne = 0.984 tons (long) 1 cubic metre m(3) (natural gas) = 35.49 cubic feet 1 tonne = 1.102 tons (short) 1 cubic metre m(3) (overburden) = 1.31 cubic yards 1 kilometre = 0.62 miles 1 hectare = 2.5 acres
NOTES: (1) Conversion using the above factors on rounded numbers appearing in this Annual Information Form may produce small differences from reported amounts. (2) Some information in this Annual Information Form is set forth in metric units and some in imperial units. CURRENCY All references in this Annual Information Form to dollar amounts are in Canadian dollars unless otherwise indicated. FORWARD-LOOKING STATEMENTS This Annual Information Form contains certain forward-looking statements that are based on Suncor's current expectations, estimates, projections and assumptions and were made by the Company in light of its experience and its perception of historical trends. All statements that address expectations or projections about the future, including statements about Suncor's strategy for growth and future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results, are forward-looking statements. Some of the forward-looking statements may be identified by words like "expects," "anticipates," "plans," "intends," "believes," "projects," "indicates," "could", "vision", "goal", "objective" and similar expressions. These statements are not guarantees of future performance and involve a number of risks, uncertainties and assumptions. Suncor's business is subject to risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements as a result of known and unknown risks, uncertainties and other factors. You are cautioned not to place undue reliance on Suncor's forward looking statements. The risks, uncertainties and other factors that could influence actual results include but are not limited to: changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; fluctuations in commodity prices; fluctuations in currency exchange rates; Suncor's ability to respond to changing markets; the ability of Suncor to receive timely regulatory approvals; the successful and timely implementation of its growth projects including the Firebag In-Situ Oil Sands Project and Project Voyageur; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development projects; Suncor's ability to comply with current and future environmental laws; the accuracy of Suncor's reserve estimates, production estimates and production levels and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venturers; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; actions by governmental authorities including tax increases and changes in government fees, changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other vii similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; and other factors, many of which are beyond Suncor's control. Suncor cautions that the foregoing list of important factors is not exhaustive. Many of these risk factors are discussed in further detail throughout this Annual Information Form and in Management's Discussion and Analysis for the year ended December 31, 2001 and dated February 28, 2002 ("MD&A"), which MD&A is incorporated by reference herein. Readers are also referred to the risk factors described in other documents Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Company at 112 - 4th Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by email request to info@suncor.com. viii CORPORATE STRUCTURE INCORPORATION OF THE ISSUER Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the CANADA BUSINESS CORPORATIONS ACT on August 22, 1979 of Sun Oil Company Limited, incorporated in 1923 and Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, Suncor amalgamated with a wholly-owned subsidiary under the CANADA BUSINESS CORPORATIONS ACT. Suncor's articles were amended in 1995 to move its registered office from Toronto, Ontario, to Calgary, Alberta, and amended again in April 1997, to adopt its current name, "Suncor Energy Inc.". In April 1997 and May 2000, Suncor's articles were amended to divide its issued and outstanding shares on a two-for-one basis. In January 2002, Suncor's Board of Directors authorized a further two-for-one common share division with a May 15, 2002, record date, subject to shareholder approval at the Company's annual meeting scheduled for April 26, 2002. Suncor's registered and principal office is located at 112 - 4th Avenue, S.W. Calgary, Alberta, T2P 2V5. In this Annual Information Form, references to "Suncor" or the "Company" include Suncor Energy Inc., its subsidiaries and joint venture investments unless the context otherwise requires. SUBSIDIARIES OF SUNCOR Suncor Energy Inc. has two principal subsidiaries. Sunoco Inc. ("Sunoco") is an Ontario corporation that is wholly-owned by Suncor. Sunoco refines and markets petroleum products and petrochemicals directly and indirectly through subsidiaries and joint ventures. In this Annual Information Form, references to "Sunoco" mean Sunoco Inc., its subsidiaries and joint venture investments, unless the context otherwise requires. Sunoco is unrelated to Sunoco, Inc. (formerly known as Sun Company, Inc.) that is headquartered in Philadelphia, Pennsylvania. Suncor Energy Marketing Inc., wholly-owned by Sunoco, is incorporated under the laws of Alberta. Suncor Energy Marketing Inc. manages Company and certain third party Alberta-based pipeline operations and markets, mainly to customers in Canada and the United States, certain crude oil, diesel fuel products, and byproducts such as petroleum coke, sulphur and gypsum produced by Suncor's Oil Sands and Natural Gas (NG) business units as well as certain other third party products. Commencing in 2002, Suncor Energy Marketing Inc. will also market the Company's natural gas production to customers in Canada and the United States and supply natural gas to Oil Sands and Sunoco. Suncor Energy Marketing Inc. also has a petrochemical marketing division that principally manages its participation in Sun Petrochemicals Company, a petrochemical product joint venture partnership. GENERAL DEVELOPMENT OF THE BUSINESS OVERVIEW Suncor is a Canada-based integrated energy company. Suncor explores for, acquires, develops, produces, and markets crude oil and natural gas, refines crude oil and markets petroleum and petrochemical products. Suncor has three principal operating business units. Oil Sands, based near Fort McMurray, Alberta, produces sweet and sour crude oil, diesel fuel and custom blended feedstocks. Natural Gas ("NG") (formerly Exploration and Production), based in Calgary, Alberta, explores for, acquires, develops and produces natural gas. Sunoco, headquartered in Toronto, Ontario, refines crude oil, markets a broad range of petroleum products, mostly in Ontario, markets petrochemical products in the United States and Europe, and markets natural gas to residential and commercial customers in Ontario. 1 While it provides hydrocarbon-based resources for the immediate energy needs of consumers, Suncor also pursues the development of low-emission and no-emission energy sources that have a reduced environmental impact. Suncor announced plans to place its renewable energy projects under the management of NG beginning in 2002. While NG will manage these projects, segmented financial data will be reported under the results for the "Corporate" segment in Suncor's financial reporting. In 2001, Suncor produced approximately 127,100 barrels per day (bpd) of crude oil and natural gas liquids (approximately 6% of Canada's crude oil production) and 177 million cubic feet per day of natural gas. In 2000, the most recent period with published results, Suncor was the third largest crude oil and natural gas liquids producer and the 26th largest natural gas producer in Canada. In 2001, Suncor sold approximately 93,400 bpd (14,800 m3 per day) of refined products, mainly in Ontario but also in the United States and Europe. Suncor's refined product sales in Ontario represented approximately 18% of Ontario's total refined product sales in 2001. THREE-YEAR HIGHLIGHTS OIL SANDS In April 1999, following approval from Suncor's Board of Directors and regulatory authorities, Suncor commenced construction of Project Millennium, an expansion of its Oil Sands plant near Ft. McMurray, Alberta. Through an expanded mine, additional mining equipment, increased energy services support and twinning of the bitumen extraction and upgrading process, Project Millennium was ultimately designed to increase production capacity of the plant to 225,000 bpd by 2002. Project Millennium was completed in 2001 at a final capital cost of $3.4 billion, up from the original estimate of $2 billion. The increase in project costs over both the original, and subsequent interim estimates, was primarily attributable to rising labour, fabrication and material costs and a $150 million change in the project's scope. The additional capital costs were financed by internally generated cash flow and additional borrowing. In October 1999, pursuant to an agreement entered into with TransAlta Energy Corporation ("TransAlta"), TransAlta assumed the role of operator of Suncor's existing Oil Sands energy services plant. Also in 1999, TransAlta commenced construction of a $315 million co-generation facility at Suncor's Oil Sands plant site. Fully operational in 2001, this TransAlta owned and operated facility is meeting a portion of Oil Sands' electricity and steam requirements as well as supplying electricity to the Alberta power grid. In early 2000, Suncor announced a plan to further expand its Oil Sands operations beyond Project Millennium and in 2001 Suncor received regulatory approval to proceed with development of the Firebag In-situ Oil Sands Project. Combined with the construction of an associated vacuum tower at the site of its plant, the first stage of Firebag is designed to add 35,000 barrels per day of bitumen production at an estimated cost of $1 billion. The current cost estimate is up from the original estimate of $750 million. Firebag construction, which commenced in 2001, is expected to continue through to 2005 when Suncor is targeting to achieve a total Oil Sands production capacity of 260,000 bpd. Three additional stages of development of the Firebag leases, which have received regulatory approval, have the potential to increase production from these leases to a total of 140,000 barrels of bitumen per day by the end of the decade. Approval from Suncor's Board of Directors is required before construction beyond the first stage can begin. In 2001, Suncor also announced plans for Voyageur, a phased expansion of the Company's oil sands mining and in-situ operations and related extraction and upgrading facilities. Management believes Voyageur has the potential to increase production capacity at Oil Sands to 500,000 to 550,000 bpd in 2010 to 2012. Suncor plans to develop Voyageur in phases with engineering, construction and production plans for each phase to be aligned with long term marketing strategies. In 2002, Suncor plans to undertake a 2 comprehensive stakeholder consultation program and integrate recommendations, as appropriate, into engineering, design and project development for Voyageur. Preliminary cost estimates for Voyageur are expected to be available in late 2002. Development of Voyageur requires approval of regulators and Suncor's Board of Directors, as well as favourable fiscal and market conditions, among other things. In 2001, Suncor commenced a crude oil brokerage business to generate additional income by buying and selling crude oil production of other companies. The activity conducted by this business did not have a significant impact on the Company's earnings or cash flow in 2001. NATURAL GAS (NG) In April 2000, Suncor's Board of Directors approved a repositioning of the Exploration and Production business and renamed it Natural Gas ("NG") to reflect the sharpened focus on natural gas production to meet growing demand, both internally and externally. In 2000, NG set a target to decrease annualized operating costs by a total of $18 million to $20 million by year-end 2001. Approximately $15 million of this target was reached in 2000. Annualized operating costs decreased an additional $5 million in 2001 through a focus on administrative cost controls and reduced lifting costs. NG's goal is to achieve a return on average capital employed (see Glossary) of at least 12% in 2002 and at least 15% in 2004 at mid-cycle natural gas prices (U.S. $3.00 to $3.50/mcf price range). Management will work toward this goal by building existing operating areas and developing new production and revenue streams. Achievement of this goal cannot be assured. See "Forward-looking statements" at the beginning of this AIF. SUNOCO In 2001, Sunoco entered into an energy supply agreement with TransAlta. Under the agreement, steam from the TransAlta Sarnia Regional Co-generation Project, a multi-user cogeneration project in Sarnia, Ontario, will be supplied to Sunoco's Sarnia Refinery. The agreement is expected to help mitigate Sunoco's exposure to increases in energy costs and supply steam to the Sarnia Refinery at a competitive cost, while eliminating the need for Sunoco to build its own steam generating boilers. According to TransAlta, the new facility is expected to commence operation in the fourth quarter of 2002. Under this agreement with TransAlta, Sunoco has the right to take a portion of the electricity output from the TransAlta Sarnia Regional Co-generation Project. If Sunoco exercised this right prior to startup of the new facility, the electricity requirements of the Sarnia Refinery would also be supplied under the agreement with TransAlta. Sunoco had entered into a conditional fixed-rate electricity supply contract with a third party in 2000 to lock-in costs on a portion of its electricity requirements for three years following deregulation of the Ontario electricity market. However, due to the delay in deregulation, this contract terminated automatically in accordance with its terms. Sunoco continues to evaluate available options with respect to long-term electricity supply and no decision has been taken by Sunoco to date with respect to the exercise of its option under the TransAlta contract. Federal legislation passed in 1999 mandates sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. Sunoco finalized an investment plan in 2001 to meet the sulphur content limits. Capital required to achieve compliance is expected to be approximately $40 million, which includes the addition of a desulphurization unit. Construction of the unit is planned for 2002 and 2003. In 2001, Sunoco completed a strategic assessment of its retail natural gas marketing business. Sunoco is currently exploring alternatives with respect to the business, including a possible disposition, joint venture or other transaction involving such business. 3 OTHER FINANCING ACTIVITIES During 1999, the Company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of U.S.$162.5 million of 9.125% preferred securities, the proceeds of which totaled Canadian $507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debt of the Company, due in 2048 and redeemable at the Company's option on or after March 15, 2004. See "Dividend Policy and Record." During 2000, the Company put in place a borrowing facility for $500 million that is fully revolving for 364 days and was scheduled to expire in 2001. In 2001 this facility was extended to June 2002 and increased to $550 million. In 2001 Suncor issued $500 million of Series 2 Medium Term Notes with a ten year maturity. The notes have a coupon of 6.7% and will yield 6.74%. In January 2002, Suncor issued U.S. $500 million principal amount of 7.15% unsecured notes due February 1, 2032, to investors in the United States (the "U.S."). The notes were sold at a price of 99.595% per note to yield 7.183% to maturity. The sale of the notes was under Suncor's shelf prospectus dated January 10, 2002, which allows for the issuance of debt securities and common shares in an aggregate principal amount of up to U.S. $1 billion. Also in January 2002, Suncor filed a base shelf prospectus with Canadian securities regulatory authorities, enabling it to issue up to a further $500 million in medium term notes in Canada, if required. To date, no notes have been issued under this prospectus. SALE OF STUART OIL SHALE PROJECT In April 2001, Sunoco sold its interest in the Stuart Oil Shale Project to its Australian joint venture co-owners, Southern Pacific Petroleum NL ("SPP") and Central Pacific Minerals NL ("CPM") (together, "SPP/CPM"). The first stage of the Queensland, Australia project, originally announced by Suncor and SPP/CPM in 1997, was designed as a 4,500 barrel per day demonstration plant to test the commercial viability of producing crude oil from oil shale. Construction of the demonstration plant was completed and commissioning commenced in 1999. Operational issues were experienced during commissioning, including issues relating to plant reliability, noise, odours and the discovery of low levels of dioxin and other emissions. In the third quarter of 2000, Suncor recorded an after-tax write-down of $80 million, reflecting increased costs and delayed oil production, and thereafter, all future expenditures on the Project were expensed. Suncor's investment in the Project up to the date of sale, excluding $4 million invested by Suncor in partially paid SPP/CPM shares that were cancelled as part of the sale transaction, and $5 million in shares acquired in 2001, as discussed below, was approximately $275 million. Under the terms of the sale, Suncor retained a 5% royalty interest in the first stage of the project, and SPP/CPM and Suncor retained worldwide rights to the project technology. Suncor made total payments as part of the transaction in the amount of Aus$7 million (approximately Cdn$5 million) for which Sunoco received 2.5 million SPP shares and 0.926 million CPM shares. In addition, SPP/CPM issued to Suncor 12.5 million SPP share options and 4.6 million CPM share options, and Suncor surrendered the partly paid SPP/CPM restricted class shares it had originally acquired in 1997. As a result of the sale an after-tax charge to earnings of $3 million was recorded in the second quarter of 2001. At the end of 2001 Suncor also partially wrote-down the carrying value of the shares acquired by $3 million. OTHER HIGHLIGHTS In September 1999, Suncor was included in the newly formed Dow Jones Sustainability Index, the world's first global equity index tracking the performance of 200 leading sustainability-driven companies in 68 industry groups in 22 countries. Suncor continued to be part of the Sustainability Index in 2000 and 2001. Suncor announced in 2000 plans to invest at least $100 million over five years to pursue renewable energy opportunities. As of December 31, 2001, Suncor hadexpended approximately $16 million with the 4 majority of these funds expended on the SunBridge Wind Power Project in Gull Lake, Saskatchewan. This project is a 50-50 partnership with Enbridge Inc. ("Enbridge"). In 2001, the first electricity was generated from this project. For further information on the status of the ongoing projects and issues referred to above and other highlights of 2001, refer to "Outlook" and other sections of Suncor's MD&A. NARRATIVE DESCRIPTION OF THE BUSINESS OIL SANDS Suncor produces a variety of refinery feedstocks and diesel fuel by mining the Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted at its plant near Fort McMurray, Alberta. The Oil Sands operations, accounting for over 99% of Suncor's conventional and synthetic crude oil production in 2001, represents a significant portion of Suncor's asset base, cash flow and earnings. OPERATIONS Suncor's integrated Oil Sands business involves four operations: a mining operation using trucks and shovels to mine the oil sand ore; extraction facilities to recover the bitumen from the oil sand ore; a heavy oil upgrading process, where bitumen is converted into crude oil products; and an energy services plant (operated by TransAlta), which together with TransAlta's natural-gas fired co-generation plant that commenced operations at the Oil Sands plant site in 2001, provides the site with steam and electric power. Suncor's energy services plant primarily uses petroleum coke, a by-product of the coking process, as fuel. It also consumes natural gas. The first step of the open pit mining operation is to remove the overburden with trucks and shovels to access the oil sands - a mixture of sand, clay and bitumen. The oil sands ore is transported to one of four sizing plants by a fleet of trucks. The ore is dumped into sizers where it is crushed and then transported to the extraction plant. On the west bank of the Athabasca River, the ore is transported by a conveyor system that stretches approximately five kilometers. On the east bank, a slurry of partially processed ore from the mine is transported by a hydrotransport system to the extraction plant on the west side of the river. Bitumen is extracted from the oil sands with a hot water process. After the final removal of impurities and minerals, naphtha is added as diluent to facilitate transportation to the upgrading plant. Periodically bitumen is sold rather than being upgraded. In 2001 approximately 8,500 bpd of bitumen were sold, representing approximately seven percent of 2001 production. After transfer to the upgrading plant, the diluted bitumen is separated into naphtha and bitumen. The naphtha is recycled to be used again as diluent and the bitumen is upgraded through a coking and distillation process. The upgraded product, referred to as sour crude oil, is either sold directly to customers or is further upgraded into sweet crude oil by removing the sulphur and nitrogen using a hydrogen treating process. Three separate streams of refined crude oil are blended together according to customer specifications. Suncor Energy Marketing Inc. purchases and ships these product blends by pipeline for sale and distribution to Suncor's Sarnia, Ontario refinery, as well as other customers in Canada and the United States. Oil Sands entered into a transportation service agreement with a subsidiary of Enbridge for a term that commenced in 1999 and extends to 2028, for pipeline capacity that allows for the initial shipment of 60,000 and increasing to 170,000 barrels per day of sour crude oil and bitumen from Fort McMurray, Alberta to Hardisty, Alberta. As the initial shipper on the pipeline, Suncor's tolls payable under the agreement are subject to annual adjustments. The pipeline is operated by Suncor Energy Marketing Inc. This pipeline, together with Suncor's proprietary oil sands pipeline, is expected to meet Suncor's anticipated crude oil shipping requirements for expected future production levels up to 2008. Suncor has an agreement TransCanada Pipeline Ventures Limited Partnership ("TCPV"), to provide Suncor with firm capacity on a new natural gas pipeline constructed by TCPV. This pipeline came into service in 1999. 5 The oil sands plant is susceptible to loss of production due to the interdependence of its component systems. In 1999 two unplanned outages of the 5C9 fractionator lasted a total of 16 days and resulted in approximately 1.8 million barrels of lost production. Parts of the 5C9 unit that failed were redesigned during the second outage in September 1999, with the objective of improving reliability and helping to achieve targeted production rates. Suncor shut down the same unit for maintenance twice in 2001, also for a total of 16 days. It is estimated that the lost production from these 2001 outages was approximately 1.8 million barrels. Management will continue to monitor the performance of this unit and evaluate whether further repairs or other remedial actions are required to address the operational issues. Through expansion projects like Millennium, Suncor expects improved operational flexibility by reducing the cash flow impact of complete plant-wide shutdowns. For example, Millennium adds a second complete processing operation. This "dual train" approach increases production capacity and provides the flexibility to schedule periodic plant maintenance on one train while continuing to generate production and cash flow from the other. Oil Sands base plant (which excludes Millennium facilities) is currently scheduled to undergo a maintenance shutdown in 2002. Suncor plans to continue producing from the Project Millennium facilities during this scheduled maintenance. During these partial shutdown maintenance periods, work can be done while the rest of the plant continues to operate. This reduces both the cost and scope of shutdowns and allows for continued production of sour crude oil during the shutdown period. Suncor has also undertaken other work to improve operational performance. Over the past several years, backup components and systems have been introduced in critical areas to improve reliability. In addition to ongoing preventive maintenance programs, full plant maintenance shutdowns are completed approximately every four years. In addition to complete shutdowns, partial shutdowns in the upgrader are undertaken periodically. Severe climatic conditions at Oil Sands can cause reduced production and in some situations result in higher costs. 6 LEASEHOLD INTERESTS AND ROYALTIES Set out in the table below is a summary of Suncor's oil sands mining and in-situ leasehold interests as of December 31, 2001.
Percentage of Proved Reserves Number of Gross (bbl of synthetic Acres crude oil for mining Referred (Net Acres if leases / bbl bitumen Description Legal Description to as applicable) for in-situ leases) - ------------------------ ---------------------- ------------ --------------------- ---------------------- MINING LEASES: - -------------- Mine Expansion: Leases 7280100T25 25 17,644 7279080T19 19 18,760 Mine Expansion 7597030T11 97 2,483 Leases and Fee Lots 7280060T23 36,954 represent 99% 7498050014 243 Fee Lots(1) 1 N/A 1,894 (1) 3 N/A 1,967 (1) 4 N/A 1,886 (1) Original Mine 7387060T04 86 4,522 Original Mine Leases 7279120092 17 1,619 Leases represent 1% TOTAL MINING LEASES 87,972 FIREBAG LEASES: - ------------------- Firebag(2) 7285100T85 85 39,594 (1) 7097110062 N/A 7,040 (1) 7097110063 N/A 5,760 (1) 7097110064 N/A 4,800 (1) 7097120065 N/A 13,440 (1) 7097120066 N/A 18,560 (1) 7097120067 N/A 19,200 (1) 7099120072 N/A 23,040 (1) 7099120073 N/A 23,040 (1) 7099120074 N/A 16,640 (1) 7099120075 N/A 23,040 (1) 7001100001 N/A 22,400 (1) 7401100027 N/A 23,040 (1) 7401100029 N/A 10,240 (1) 7401100013 N/A 7,360 (1) Firebag(2) Various(3) Various 84,480 (1) TOTAL FIREBAG LEASES 341,674 TOTAL LEASES 429,646
7 Notes: (1) No proved reserves are attributable to these leases. (2) Leases are principally in-situ. (3) Suncor holds a beneficial interest in 13 leases totaling 84,480 gross and net acres. The Government of Alberta is entitled to royalties under Leases 17, 19, 25, 86 and 97 and the Fee Lots at rates which the Government establishes from time to time. Under the Alberta Suncor Crown Royalty Agreement, Crown royalties are 25% of net revenues less allowable costs (including capital expenditures), subject to a minimum payment of 5% of gross revenues. In 2001, the minimum royalty rate changed to 1% of gross revenues. Suncor currently expects to pay Crown royalties at the minimum 1% rate until 2009, based on assumptions relating to future crude oil prices, production levels, operating costs and capital expenditures. In 2000, Suncor made Crown royalty payments based upon the 5% minimum royalty. Suncor transitioned to a generic Oil Sands royalty agreement with the Alberta government in 1999 that provides Suncor with additional allowable cost deductions to a maximum of $158 million per year for ten years (related to Suncor's original investment in the Oil Sands facility). Anadarko Inc. (a successor to Norcen Energy Resources Limited) has a gross overriding royalty on Lease 86 pursuant to an agreement dated March 1, 1989 (the "Anadarko Royalty"). The Anadarko Royalty is based on a graduated scale dependent on the synthetic crude oil price expressed as a percentage of gross revenue from production of the lease. As of December 31, 2001, under the Anadarko Royalty, no payment is required if synthetic crude prices are below $20.15 per barrel. Payment of 1.5% of gross revenue is required if the synthetic crude price ranges from $20.15 to $21.14 per barrel. For every $1.00 per barrel increase in the price of synthetic crude in the range of $21.15 to $26.14 per barrel, the percentage rate of the royalty increases by 0.5%. For every $1.00 per barrel increase in the price of synthetic crude in the range of $26.15 to $37.14 per barrel, the percentage rate of the royalty increases by a further 0.25 % until a maximum royalty of 7% is reached. All synthetic crude prices are calculated on a monthly average basis and the crude price break points are adjusted annually on March 1 of each year by a contractually determined inflation component. Suncor currently expects to complete mining on the Anadarko lease in 2002. Petro-Canada has a royalty on Lease 19 pursuant to an agreement dated October 6, 1992. The royalty is calculated as 1.5% of net sale proceeds. Net sale proceeds are calculated based upon a formula by which the sale proceeds for the period exceeds the sum of allowed deductions for the period. The Crown royalty regime applicable to the Firebag in-situ leases will be the same regime as described for Suncor's oil sands mining leases above. To date, Suncor has had no commercial production from this area and none is expected until 2004-2005. ESTIMATED RESERVES Suncor estimates its mining leases, on a combined basis, contain proved plus probable reserves of synthetic crude oil totaling 2.405 billion barrels, with 376 million barrels classified as proved. Its in-situ leases, on a combined basis, contain probable reserves of 2.029 billion barrels of bitumen. In the case of Firebag in-situ bitumen reserves, Suncor has the option of selling this bitumen production and/or upgrading the bitumen to synthetic crude oil. Suncor's current upgrading operations have a synthetic crude oil yield of 80%. These estimates are before deduction of Crown and applicable royalties on the leases. Under the Crown Royalty Agreement the Crown royalty is dependent on deemed net revenues (Revenue-Cost, or R-C); therefore the calculation of net reserves would vary depending upon production rates, prices and operating and capital costs. The mining reserve estimates are based upon a detailed geological assessment including drilling density 8 and laboratory tests and also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints. Based on these factors, additional proved reserves are anticipated to be recognized as the mine is further developed. The current proved plus probable reserve estimate is based on an additional 30 years of operations without further expansion. Suncor engaged Gilbert Laustsen Jung Associates Ltd. ("GLJ"), independent petroleum engineering consultants, to audit Suncor's estimate of proved and probable reserves of synthetic crude oil on its mining leases, as of December 31, 2001. A synthetic crude oil yield of 80% has been utilized in the determination of the proved and probable reserves. The proved reserves exclude areas within the current pit designed not drilled up to a density of at least 10 holes per square kilometer. The proved plus probable reserves are based upon a production forecast recognizing 30 additional years of mining operations (210,000 bpd in 2002 and 220,000 bpd thereafter). Suncor is considering pit design changes to the Millennium mine associated with higher stripping ratio areas, permitted under operating criteria issued by the Alberta Energy and Utilities Board in 2001. The current proved plus probable volumes are now 58 million barrels higher than current model estimates which reflect the proposed changes. This difference in estimates corresponds to about 9 months of anticipated production, and is considered to be within the accuracy of the model estimates. The pit designs will continue to be impacted by both additional drilling data and operating experience, as well as technology developments and economic considerations. Furthermore, the potential exists to expand mining operations north across the Steepbank River, to develop an ore body not yet classified as a reserve. In their opinion dated January 16, 2002, GLJ state they believe there is at least a 90% and 50% confidence the proved and proved plus probable mining reserves estimates will be exceeded, respectively. Their opinion is qualified to the extent that it assumes Suncor will comply with any amendments that may be made to regulatory approvals. At Suncor's request GLJ has prepared an independent resource and economic analysis of Suncor's Firebag in-situ oil sands project leases. Suncor's geologic interpretation of the leases was provided to GLJ, who reviewed Suncor's methodology and interpretation and then prepared independent interpretations. GLJ's interpretation was based on an analysis of individual well data and 3D and 2D seismic data supplied by Suncor. GLJ based its interpretation on current pricing and royalty assumptions. In addition, GLJ utilized estimates and assumptions for factors such as recovery efficiencies and operating costs, based on GLJ's experience with similar projects. Cost and construction schedule estimates were supplied by Suncor. Based upon the work conducted by GLJ as described above, GLJ estimates that there are 9.6 billion barrels of bitumen resources on the Firebag leases, which includes a total 2.029 billion barrels that are probable nonproducing bitumen working interest reserves within the project approved area. Suncor continues to conduct its evaluation program in the Firebag area in 2002, utilizing a combination of seismic and corehole drilling. This process is expected to be ongoing over a number of years. The program is intended to assist Suncor in evaluating the potential bitumen resources in order satisfy oil sands lease tenure regulations, obtain sufficient geological data to quantify the resources on the leases, and gain a more detailed understanding of the resource to facilitate future design and layout of production wells. To date Suncor has drilled approximately 300 coreholes and acquired approximately 400 miles of seismic data in the Firebag area. Programs are conducted annually to gain the information needed to guide resource development. 9 RESERVES RECONCILIATION The following table sets out a reconciliation of Suncor's proved and probable reserves of synthetic crude oil and bitumen from December 31, 2000 to December 31, 2001, based on reports issued by GLJ as described above (the "GLJ Oil Sands Reports").
Mining Reserves(2) Insitu Firebag(3) ------------------ ----------------- Total Mining (millions of barrels of synthetic crude (millions of barrels of and In-Situ oil) bitumen) Proved and Proved Probable Total Probable Probable -------- -------- ----- -------- ----------- December 31, 2000.......... 422 2,034 2,456 - 2,456 Revisions(1)............... (1) (5) (6) - (6) Additions.................. - - - 2,029 2,029 Production................. (45) - (45) - (45) ---- - ---- - ---- December 31, 2001.......... 376 2,029 2,405 2,029 4,434
Note: (1) Revisions relate to drilling activity, revisions to the pit design based upon both geotechnical and economic data related to the Mine Expansion leases (see the table under the heading "Leasehold Interests and Royalties") and operational issues. (2) Synthetic crude oil reserves based upon a net coker, or synthetic crude oil yield of 80%. (3) Suncor has the option of selling the bitumen production from these leases and/or upgrading the bitumen to synthetic crude oil. REVENUES FROM SYNTHETIC CRUDE OIL AND DIESEL Although revenues after royalties per barrel are higher for synthetic crude oil than for conventional crude oil, operating costs to produce synthetic crude oil are higher than lifting and administrative costs to produce conventional crude oil from the Western Canada Sedimentary Basin. While there is no finding cost associated with synthetic crude oil, mine development and expansion of production can entail significant outlays of funds. The costs associated with synthetic crude oil production are largely fixed for the same reason and, as a result, operating costs per unit are largely dependent on levels of production. Aside from onsite fuel use, all of Oil Sands production is sold to Suncor Energy Marketing Inc., a wholly owned subsidiary of Sunoco, which then markets the production. In 1997, Suncor and Shell Canada ("Shell") renewed a purchase agreement whereby Shell agreed to purchase and receive approximately 95,000 cubic metres (approximately 600,000 barrels) of sweet synthetic crude oil per month. The original term of the agreement was to December 31, 1997, with 60-day evergreen terms thereafter. The price received is based on a formula involving postings for sweet crude oil. With Millennium start-up, Suncor also entered into a one-year agreement effective January 1, 2002 to sell an additional 28,600 cubic meters (180,000 barrels) per month to Shell under the same pricing terms. In 1997 Suncor entered into a long-term agreement with Koch Oil Co. Ltd. ("Koch") to supply Koch with up to 30,000 barrels per day (approximately 26% of Suncor's average 2001 total production) of sour crude from Suncor's Oil Sands operation. Suncor began shipping the crude to Koch's refinery in Minnesota under this long-term agreement effective January 1, 1999. The initial term of the agreement extends to January 1, 2009, with month to month evergreen terms thereafter, subject to termination after January 1, 2004, on twenty-four months' notice. In 2000, Suncor announced a long term sales agreement with Consumers Co-operative Refineries Limited ("CCRL") under which Suncor expects to begin supplying CCRL with 20,000 barrels per day of sour crude oil production from its Project Millennium expansion facilities by late 2002. Prices for sour crude oil under these agreements are set at agreed differentials to market benchmarks. In 2001, Suncor announced a long-term agreement with Petro- 10 Canada to supply up to 30,000 barrels per day of diluent to dilute bitumen produced by Petro-Canada. The contract is expected to commence in 2002 and is a four year agreement that will be extended unless terminated by either party. In 2001, Koch was the only customer that represented 10% or more of Suncor's consolidated revenues, while there were two such customers in 2000, Koch and Shell. A portion of Oil Sands production is used in connection with Suncor's Sarnia refining operations. During 2001, the Sarnia refinery processed approximately 14% (2000 -- 25%) of Oil Sands crude oil production. The following table sets forth the average sales price received per barrel of synthetic crude oil from Oil Sands on a quarterly basis for the years 2001 and 2000, after the impact of hedging activities.
- -------------------------------------------------------------------------------------------------------------------- 2001 2000 ------------------------------------------------ ------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------- $/bbl 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q ----- -- -- -- -- -- -- -- -- Average sales 24.43 31.43 31.40 30.85 31.33 32.39 31.12 31.84 price - --------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES Capital spending at Oil Sands is expected to total approximately $600 million in 2002, $420 million with respect to the in-situ phase of Suncor's Oil Sands development and expansion of the upgrading facilities and $180 million in capital investments for the current facility. Capital expenditures in 2001 were approximately $1.5 billion. Suncor's in-situ spending of $420 million in 2002 is part of $1 billion in total spending on in-situ projects planned for the period 2002 to 2005. The following table sets out, for the quarters indicated, capital expenditures by Suncor's Oil Sands business unit:
- ----------------------------------------------------------------------------------------------------------------------- 2001 2000 - ----------------------------------------------------------------------------------------------------------------------- CAPITAL EXPENDITURES BY QUARTER 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q -- -- -- -- -- -- -- -- - ----------------------------------------------------------------------------------------------------------------------- Property acquisitions 4 - - 9 13 4 - - - ----------------------------------------------------------------------------------------------------------------------- Drilling activity 4 - 4 14 1 - - - - ----------------------------------------------------------------------------------------------------------------------- Capital Additions to Facilities (1) 305 384 392 363 466 363 552 409 - -----------------------------------------------------------------------------------------------------------------------
Note: (1) Includes capital spending on Project Millennium, Firebag Oil Sands Projects, acquisition of mining equipment, and other capital spending 11 ENVIRONMENTAL COMPLIANCE For a description of the impact of environmental protection requirements on Oil Sands, refer to "Environmental Risks" and "Government Regulation" in the "Risk/Success Factors" section of this AIF. NATURAL GAS Suncor's Natural Gas business, based in Calgary, Alberta, explores for, develops and produces conventional natural gas in western Canada, supplying it to markets throughout North America. The sale of NG production provides an internal hedge for natural gas consumption at Suncor's Oil Sands and Sunoco businesses. In addition, Suncor's U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is acquiring land and exploring for coal bed methane in the United States. In April 2000, Suncor's Board of Directors approved a repositioning of the Exploration and Production business and renamed it Natural Gas to reflect a sharpened focus on natural gas production. The repositioning entailed the consolidation of production in three core natural gas areas, and a restructuring of business processes to support the new focus. During 2000, NG targeted its natural gas focus in Western Canada by concentrating on natural gas prospects and selling most of its conventional crude oil properties. Exiting 2001, natural gas and natural gas liquids accounted for approximately 94% of the NG business unit's production. Suncor's exploration program is focused on multiple geological zones in three core asset areas: Northern (northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast British Columbia) and Central Alberta. Suncor drills primarily medium to high-risk wells focusing on prospects that can be connected to existing infrastructure. An in-house natural gas marketing group sells Suncor's proprietary natural gas and natural gas acquired from other producers. During 1997, Suncor entered into a five-year agreement with Enron Capital and Trade Resources Canada Corp. ("ECT") for ECT to provide operational and administrative services to Suncor related to its natural gas portfolio. This agreement was terminated without cost to Suncor in December 2001. ECT continues to provide natural gas related operational and administrative services to Suncor under a short-term agreement. RESERVES AND RESERVES RECONCILIATION GLJ reported January 29, 2002, on Suncor's estimated proved and probable reserves of natural gas, natural gas liquids and crude oil (other than reserves from Suncor's mining leases and the Firebag in-situ reserves), as of December 31, 2001. Information with respect to these reserves is set out in the tables below and in the tables under the headings "Crude Oil and Natural Gas Liquids" and "Natural Gas" (the "Reserves Tables"). GLJ's determination of Suncor's estimated proved and probable recoverable reserves are based on constant year end prices and costs determined as of the dates indicated with no escalation into the future. The accuracy of any reserve estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates presented are considered reasonable, the estimates should be viewed with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. IN THE RESERVES TABLES: (1) Proved reserves and probable reserves have the meanings set out in the Glossary of Terms at the front of this Annual Information Form. All proved and probable reserves are in Canada. (2) Proved developed reserves are on production, or reserves that could be recovered from existing wells or facilities, if the Company placed them on production. 12 (3) Gross reserves represent the aggregate of Suncor's undivided percentage interest in reserves including the royalty interest of governments and others in such reserves and Suncor's royalty interest in reserves of others. Net reserves are gross reserves less that royalty interest share of others including governments. Royalties can vary depending upon selling prices, production volumes, and timing of initial production and changes in legislation. Net reserves have been calculated following generally accepted guidelines, on the basis of prices and the royalty structure in effect at year-end and anticipated production rates. Such estimates by their very nature are inexact and subject to constant revision. The following tables set out a reconciliation of NG's estimated proved reserves from December 31, 2000 to December 31, 2001. ESTIMATED PROVED RESERVES RECONCILIATION(1)
GROSS NET ----- --- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS -------------------- ------------------- -------------------- ------------------- (MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC FEET) FEET) December 31, 2000............... 16(1) 797 11 567 Revisions of previous estimates. (1) (3) - 4 Extension and discoveries....... - 27 - 20 Production...................... (1) (65) (1) (45) Sales of minerals in place...... - (1) - (1) ------- ------ ------ ------- December 31, 2001............... 14(1) 755 10 545 ======= ====== ====== =======
Note: (1) Includes 8.6 million barrels of natural gas liquids as at December 31, 2001 (9.2 million barrels as at December 31, 2000). Estimated proved reserves are comprised of developed and undeveloped reserves. The following tables show the breakdown between these categories. ESTIMATED PROVED DEVELOPED RESERVES RECONCILIATION
GROSS NET ----- --- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS -------------------- ------------------- -------------------- ------------------- (MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC FEET) FEET) December 31, 2000............... 13 573 9 409 Revisions of previous estimates. (1) 31 - 27 Extension and discoveries....... - 34 - 25 Production...................... (1) (65) (1) (45) Sales of minerals in place...... - - - - ------- -------- ------- ------ December 31, 2001............... 11 573 8 416 ======= ======== ======= ======
13 ESTIMATED PROVED UNDEVELOPED RESERVES RECONCILIATION
GROSS NET ----- --- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS -------------------- ------------------- -------------------- ------------------- (MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC FEET) FEET) December 31, 2000................ 3 224 2 158 Revisions of previous estimates.. - (34) - (23) Extension and discoveries........ - (7) - (5) Sales of minerals in place....... - (1) - (1) ----- ----- ----- ----- December 31, 2001................ 3 182 2 129 ===== ===== ===== =====
The following table sets out a reconciliation of NG's estimated probable reserves from December 31, 2000 to December 31, 2001. ESTIMATED PROBABLE RESERVES RECONCILIATION
GROSS NET ----- --- CRUDE OIL AND CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS NATURAL GAS LIQUIDS NATURAL GAS -------------------- ------------------- -------------------- ------------------- (MILLIONS OF BARRELS) (BILLIONS OF CUBIC (MILLIONS OF BARRELS) (BILLIONS OF CUBIC FEET) FEET) December 31, 2000................ 7 304 5 217 Revisions of previous estimates.. (1) (80) - (57) Purchases of minerals in place... - - - - Extension and discoveries........ - 16 - 11 Sales of minerals in place....... - (3) - (2) December 31, 2001................ 6 237 5 169 ===== ====== ===== =======
CONVENTIONAL CRUDE OIL The following table shows estimates of NG's proved crude oil reserves before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation") and Suncor's average daily production of crude oil before royalties, in Alberta and British Columbia, represented by the conventional fields identified in this table. 14
PROVED RESERVES 2001 AVERAGE BEFORE ROYALTIES AT DAILY PRODUCTION DECEMBER 31, 2001(1) BEFORE ROYALTIES(3) -------------------- ------------------- (MILLIONS OF (BARRELS OF FIELDS BARRELS) % OIL PER DAY) % --------------------------- Simonette.............................. 2.3 47 647 44 Blueberry.............................. 1.8 37 374 25 McKinley............................... 0.2 4 120 8 Bonanza................................ 0.2 4 61 4 Rosevear............................... 0.1 2 133 9 Boundary Lake.......................... 0.1 2 25 2 Other(2)............................... 0.3 4 110 8 --- --- ------ --- Total-- gross.......................... 5 100 1,470 100 === === ====== ===
Notes: (1) The reserves and production in this table do not include natural gas liquids. (2) Includes fields in which Suncor holds overriding royalty interests. (3) Production in 2001 was materially different from 2000 due to strategic divestments. Most of the large conventional oil fields in the western provinces have been in production for a number of years and the rate of production in these fields is subject to natural decline. In some cases, additional amounts of crude oil can be recovered by using various methods of enhanced crude oil recovery, infill drilling and production optimization techniques. At the end of 2001, approximately 90% of Suncor's proved conventional oil reserves were under enhanced oil recovery programs. 15 NATURAL GAS LIQUIDS The following table shows estimates of NG's proved natural gas liquids reserves before royalties as prepared by GLJ (see "Reserves and Reserves Reconciliation") and Suncor's average daily production of natural gas liquids before royalties, in Alberta and British Columbia, represented by the conventional fields identified in this table.
PROVED RESERVES 2001 AVERAGE BEFORE ROYALTIES AT DAILY PRODUCTION DECEMBER 31, 2001 BEFORE ROYALTIES -------------------- ------------------- (MILLIONS OF (BARRELS OF FIELDS BARRELS) % OIL PER DAY) % --------------------------- Simonette............................... 2.0 23 502 21 Grande Prairie.......................... 1.4 16 183 8 Knopcik................................. 1.2 14 389 16 Pine Creek.............................. 0.8 9 247 10 Glacier................................. 0.5 6 94 4 Stolberg................................ 0.5 6 49 2 Blueberry............................... 0.5 6 164 7 Rosevear................................ 0.4 5 227 10 Blackstone.............................. 0.3 4 68 3 Phoenix................................. 0.2 2 36 2 George.................................. 0.1 1 175 7 Hinton.................................. 0.1 1 53 2 Mountain Park........................... 0.1 1 18 1 Boundary Lake........................... 0.1 1 23 1 Other(1)................................ 0.8 5 141 6 --- --- ------ --- Total-- gross........................... 9 100 2,369 100 === === ====== ===
Note: (1) Includes fields in which Suncor holds overriding royalty interests. 16 NATURAL GAS The following table shows estimates of NG's proved natural gas reserves, before royalties, as prepared by GLJ (see "Reserves and Reserves Reconciliation") and Suncor's average daily production of natural gas before royalties, in Alberta and British Columbia, represented by the major natural gas fields identified in the table.
PROVED RESERVES 2001 AVERAGE BEFORE ROYALTIES AT DAILY PRODUCTION DECEMBER 31, 2001 BEFORE ROYALTIES -------------------- ------------------- (MILLIONS OF (BARRELS OF FIELDS BARRELS) % OIL PER DAY) % --------------------------- Stolberg............................... 216 29 22 12 Blackstone/Brown Creek................. 79 11 21 12 Grande Prairie area.................... 59 8 7 4 Mountain Park.......................... 52 7 11 6 Knopcik area........................... 50 7 16 9 Glacier................................ 49 6 8 5 Simonette.............................. 40 5 9 5 Rosevear............................... 39 5 21 12 Blueberry.............................. 38 5 11 6 Sinclair............................... 20 3 7 4 Pine Creek............................. 18 2 6 3 Cutbank................................ 16 2 12 7 Other(1)............................... 79 10 26 15 --- --- --- --- Total-- Gross.......................... 755 100 177 100 === === === ===
Note: (1) Includes fields in which Suncor holds overriding royalty interests. LAND HOLDINGS The following table sets out the undeveloped and developed lands in which the NG business unit held crude oil and natural gas interests at the end of 2001. Undeveloped lands are lands within their primary term upon which no well has been drilled. Developed lands are lands past their primary term or upon which a well has been drilled. The petroleum and natural gas interests include Suncor's undivided percentage interest in leases, licenses, reservations, permits or exploration agreements (collectively, the "Agreements"). In general, Agreements confer upon the lessee the right to explore for and remove crude oil and natural gas from the lands, with the lessee paying exploration and development costs, operating costs, abandonment costs and reclamation costs, subject to paying rentals, taxes and royalties. Interests in Agreements (excluding freehold agreements) are acquired from the federal or provincial governments through competitive bidding or by undertaking work commitments, or by joint venture agreements with industry companies. 17
UNDEVELOPED ACRES ----------------- GROSS ACRES(1) NET ACRES(1) -------------- ------------ (THOUSANDS) CANADA Western provinces 627 508 INTERNATIONAL 1,685 1,227 ===== ===== Total Undeveloped Landholdings 2,312 1,735 ===== ===== Note: (1) "Gross Acres" means all of the acres in which Suncor has either an entire or undivided percentage interest in. "Net Acres" represents the acres remaining after deducting the undivided percentage interests of others from the gross acres. DRILLING The following table sets forth the gross and net exploratory and development wells, in Western Canada, the United States and Australia, which were completed, capped or abandoned in which Suncor participated during the years indicated. YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 ---- ---- GROSS NET GROSS NET ----- --- ----- --- Exploratory Wells Crude oil............................ - - - - Gas.................................. 5 4 3 1 Dry (1).............................. 22 16 17 15 Total Exploratory Wells................... 27 20 20 16 ---- ---- ---- ---- Development Wells Crude oil............................ 1 - 5 2 Gas.................................. 24 16 23 14 Dry.................................. 4 2 4 3 - - - - Total Development Wells .................. 29 18 32 19 ---- ---- ---- ---- Total..................................... 56 38 52 35 ==== ==== ==== ====
NOTE: (1) Includes 18 gross (14 net) coal bed methane wells in 2001. Not included are earning wells completed by other companies under farmout agreements relating to lands in which Suncor has an undivided percentage interest, since Suncor did not incur cash expenditures in connection with such wells. In addition to the above wells, Suncor had interests in 27 gross (14 net) exploratory wells in progress and 12 gross (seven net) development wells in progress at the end of 2001. Suncor continues to hold interests in frontier properties (Arctic and Northwest Territories) including 28 long-term "significant discovery licences". 18 WELLS The following table summarizes the wells in which the NG business unit has a working interest or a royalty interest as at December 31, 2001.
Producing Non-Producing Wells(1)(2) Wells(1)(3) ----------- ------------- Gross Net Gross Net ----- ---- ----- ---- CONVENTIONAL CRUDE OIL WELLS Alberta.............................................................. 47 32 20 17 British Columbia..................................................... 24 11 6 3 Total Conventional Crude Oil Wells........................................ 71 43 26 20 -- -- -- -- CONVENTIONAL NATURAL GAS WELLS Alberta.............................................................. 269 148 48 25 British Columbia..................................................... 49 24 17 12 TOTAL CONVENTIONAL NATURAL GAS WELLS...................................... 318 172 65 37 --- --- -- -- TOTAL WELLS 389 215 91 57 === === == ==
Notes: (1) Gross wells represent the number of wells in which NG has an undivided percentage interest and net wells represent NG's aggregate undivided percentage interest share in such wells. (2) Producing wells are wells producing hydrocarbons or having the potential to produce, excluding shut-in wells. As at December 31, 2001 Suncor has interests in four oil fields and 29 gas fields. (3) Non-Producing Wells represent management's estimate of shut-in wells that could be capable of economic production but were not on production as at December 31, 2001. SALES AND SALES REVENUES The following table shows the breakdown of NG's sources of revenues.
YEAR ENDED GROSS REVENUES(1) DECEMBER 31, ------------------ 2001 2000 ---- ---- ($ MILLIONS) Crude oil and natural gas liquids......................................................... 45 77 Natural gas............................................................................... 394 344 Pipeline.................................................................................. 5 6 Other..................................................................................... 5 1 --- --- Total..................................................................................... 449 428 === ===
Note: (1) Includes intersegment revenues. 19 PRODUCTION COSTS The following shows production (lifting) costs in connection with NG's crude oil and natural gas operations for the years indicated. In 2001, Suncor began to convert natural gas to barrels of oil equivalent (BOE) at a 6:1 ratio (thousand cubic feet of natural gas: barrel of oil); previously, conversion was on a 10:1 basis. Figures prior to 2001 have been restated on a 6:1 basis.
YEAR ENDED PRODUCTION (LIFTING) COSTS DECEMBER 31, ------------------ 2001 2000 ---- ---- ($ PER BOE OF GROSS PRODUCTION) Average production (lifting) cost of conventional crude oil and gas(1)................................ 2.96 3.11
Note: (1) Production (lifting) costs include all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems. It does not include an estimate for future reclamation costs. 20 QUARTERLY VOLUMES AND NETBACK ANALYSIS The following table shows Suncor's average production volumes, pricing, royalties, operating expenses and netbacks for natural gas, conventional crude oil and natural gas liquids, for the periods indicated.
2001 2000 ------------------------------------------------------ ----------------------------------------------------- 4Q 3Q 2Q 1Q 2001 4Q 3Q 2Q 1Q 2000 -------- -------- ------- ------- -------- -------- --------- ------- ------- ------- NATURAL GAS Production Volume (mmcf/day) 180 176 177 177 177 183 200 195 222 200 -------- -------- ------- ------- -------- -------- --------- ------- ------- ------- Price ($/mcf) 3.10 3.90 6.78 10.73 6.09 8.02 4.63 3.70 2.96 4.72 Royalties ($/mcf) (0.54) (0.85) (1.58) (2.91) (1.46) (2.14) (1.09) (0.85) (0.61) (1.17) Operating Expenses ($/mcf) (1) (0.97) (0.79) (0.95) (0.73) (0.86) (0.95) (0.68) (0.77) (0.66) (0.76) --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- Netback ($/mcf) 1.59 2.26 4.25 7.09 3.77 4.93 2.86 2.08 1.69 2.79 --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- CONVENTIONAL CRUDE OIL Production Volume (kbbls/d) (2) 1.3 1.5 1.5 1.7 1.5 1.6 3.6 3.5 8.1 4.2 --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- Price ($/bbl) 27.17 33.17 36.75 37.35 34.35 36.01 33.09 30.04 26.30 29.50 Royalties ($/ bbl) (1.84) (2.46) (2.60) (2.89) (2.45) (11.52) (9.70) (8.29) (8.31) (9.46) Operating Expenses ($/ bbl) (1) (7.25) (4.76) (5.69) (3.85) (5.17) (9.47) (6.79) (7.65) (6.62) (7.63) --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- Netback ($/bbl) 18.08 25.95 28.46 30.61 26.73 15.02 16.60 14.10 11.37 12.41 --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- NATURAL GAS LIQUIDS Production Volume (kbbls/d) (2) 2.4 2.4 2.3 2.3 2.4 2.5 2.8 3.1 3.5 3.0 --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- Price ($/bbl) 23.47 30.26 39.32 45.07 34.38 43.00 39.56 32.80 33.16 36.66 Royalties ($/ bbl) (5.96) (10.26) (10.77) (12.86) (9.93) (12.62) (11.50) (9.55) (9.25) (10.73) Operating Expenses ($/ bbl) (1) (5.83) (4.75) (5.72) (4.40) (5.17) (9.47) (6.79) (7.65) (6.62) (7.63) --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- Netback ($/bbl) 11.68 15.25 22.83 27.81 19.28 20.91 21.27 15.60 17.29 18.30 --------- -------- ------- ------- -------- -------- --------- -------- -------- ------- --------- -------- ------- ------- -------- -------- --------- -------- -------- -------
Note: (1) Operating expenses includes production (lifting) costs and administrative expenses. (2) Thousands of barrels per day 21 MARKETING, PIPELINE AND OTHER OPERATIONS Suncor operates gas processing plants at South Rosevear, Pine Creek, Boundary Lake South, Progress and Simonette with a total design capacity of approximately 206 million cubic feet per day (mmcf/day). Suncor's capacity interest in these gas processing plants is approximately 128 mmcf/day. Suncor also has varying undivided percentage interests in natural gas processing plants operated by other companies. Approximately 69% of Suncor's natural gas production is marketed under direct sales arrangements to customers in Alberta, eastern Canada, and the United States. Contracts for these direct sales arrangements are of varied terms, with a majority having terms of one year or less, and incorporate pricing which is either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference price. Under these contracts, NG is responsible for transportation arrangements to the point of sale. Sales to the United States are made under a variety of arrangements with different transportation and pricing terms. NG's direct sales arrangements include some of the natural gas consumed in Suncor's Oil Sands plant at Fort McMurray and in its downstream operations. Approximately 31% of Suncor's natural gas production is sold under existing contracts to aggregators ("system sales"). Proceeds received by producers under these sales arrangements are determined on a netback basis, whereby each producer receives revenue equal to its proportionate share of sales less regulated transportation charges and a marketing fee. Most of NG's system sales volumes are contracted to TransCanada Gas Services and Pan-Alberta Gas Ltd. These companies resell this natural gas primarily to eastern Canadian and midwest and eastern United States markets. To ensure ongoing direct sales access to markets in the United States, NG has entered into long-term gas pipeline transportation contracts. Suncor currently has 14 million cubic feet per day of firm capacity on the Northern Border Pipeline to the U.S. midwest that expires October 31, 2003. Suncor also has firm capacity of 40 mmcf/day on the Pacific Gas Transmission ("PGT") pipeline to the California border extending to the year 2023. Suncor's conventional crude oil production is used in its refining operations, exchanged for other crude oil with Canadian or U.S. refiners, or sold to Canadian and U.S. purchasers. Sales are generally made under spot contracts or under contracts that are terminable on relatively short notice. Suncor's conventional crude oil production is shipped on pipelines operated by independent pipeline companies. NG currently has no pipeline commitments related to the shipment of crude oil. The Suncor-owned Albersun pipeline, operated by Suncor Energy Marketing Inc., was constructed in 1968 to transport natural gas to the Oil Sands plant. It extends approximately 300 kilometres south of the plant and connects with the TCPL Alberta intra-provincial pipeline system. The Albersun pipeline has the capacity to move in excess of 100 mmcf/day of natural gas. Suncor arranges for natural gas supply and controls most of the natural gas on the system under delivery based contracts. The pipeline moves natural gas both north and south for Suncor and other shippers. In 2001, throughput on Albersun pipeline was 66 mmcf/day and revenues were approximately $5 million. CAPITAL AND EXPLORATION EXPENDITURES The following table sets out, for the quarters indicated, capital expenditures by Suncor's NG business unit:
- -------------------------------------------------------------------------------------------------------------------- 2001 2000 - -------------------------------------------------------------------------------------------------------------------- ($ millions) 4Q 3Q 2Q 1Q 4Q 3Q 2Q 1Q - -------------------------------------------------------------------------------------------------------------------- Property Acquisition - - - - 8 - 2 1 - -------------------------------------------------------------------------------------------------------------------- Exploration 29 4 14 3 17 9 6 18 - -------------------------------------------------------------------------------------------------------------------- Development 19 20 17 26 8 13 3 42 - --------------------------------------------------------------------------------------------------------------------
22 NG expects to spend $140 million in 2002 to support the Company's goal of increasing natural gas production. ENVIRONMENTAL COMPLIANCE For a description of the impact of environmental protection requirements on NG, refer to "Environmental Risks" and "Government Regulation" in the "Risk/Success Factors" section of this AIF. SUNOCO Suncor refines and markets petroleum products in central Canada through its wholly owned subsidiary, Sunoco Inc.. Its refinery in Sarnia, Ontario, refines petroleum feedstocks from Oil Sands and other sources into gasoline, distillates and petrochemicals. Sunoco's controlled distribution channels enhance its position in the Ontario market. Approximately 59% of Sunoco's sales volume in 2001 was sold through controlled distribution networks in Ontario that sell gasoline and diesel to retail customers. Approximately 38% was sold to industrial, commercial, wholesale and refining customers in Ontario and Quebec, primarily jet fuels, diesel and gasolines. The remaining 3% represents petrochemical sales through Sun Petrochemicals Company, a 50% joint venture between Sunoco and a U.S. refinery. Sunoco also markets natural gas to approximately 125,000 commercial and residential customer accounts in Ontario. In 2001, Sunoco completed a strategic assessment of this business, and is currently exploring alternatives including a possible disposition, joint venture, or other transaction involving such business. Sunoco's financial reporting in 2001 is based on its Rack Back / Rack Forward organizational structure. The Rack-Back division procures and refines crude oil and feedstocks, and sells and distributes to the Sarnia refinery's largest industrial and reseller customers. The Rack-Forward division is comprised of retail operations, retail natural gas marketing, cardlock and industrial / commercial sales, and the UPI Inc. ("UPI") and Pioneer Group Inc. ("Pioneer") joint venture businesses. UPI is a 50% joint venture company owned by Sunoco and GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing cooperative. Pioneer is an independent retailer with which Sunoco has a 50% joint venture partnership. PROCUREMENT OF FEEDSTOCKS Sunoco's refining operation uses both synthetic and conventional crude oil. Sunoco procured approximately 47% of its synthetic crude oil feedstock from Suncor's Oil Sands production in 2001, compared with 56% in 2000. In 2001, 55% of the crude oil refined at the Sarnia Refinery was synthetic crude oil, compared with 64% in 2000. The balance of the refinery's synthetic crude oil, as well as its conventional and condensate feedstocks, were purchased from others under month to month contracts. In the event of a significant disruption in the supply of synthetic crude oil, the refinery has the flexibility to substitute other sources of sweet or sour conventional crude oil. Sunoco procures its conventional crude oil feedstock primarily from western Canada, supplemented from time to time with crude oil from the United States and other countries. Foreign crude oil is delivered to Sarnia via pipeline from the United States Gulf Coast or via the Interprovincial Pipeline from Montreal. Sunoco has made no firm commitments for capacity on these pipeline systems. Crude oil is procured from the market on a spot basis or under contracts terminable on short notice. In 1998, Sunoco signed a 10-year synergistic feedstock agreement with a Sarnia-based petrochemical refinery, Nova Chemicals (Canada) Ltd. Under this buy/sell agreement, Sunoco obtains feedstock that is more suitable for production of transportation fuels in exchange for feedstock more suitable for petrochemical cracking. Sunoco also enters into reciprocal buy/sell or exchange arrangements with other refining companies from time to time as a means to minimize transportation costs, balance product 23 availability and enhance refinery utilization. Sunoco also purchases refined products in order to meet customer requirements. REFINING OPERATIONS Sunoco's Sarnia Refinery produces transportation fuels (gasoline, diesel, propane and jet fuel), heating fuels, liquefied petroleum gases, residual fuel oil, asphalt feedstock, benzene, toluene, mixed xylenes and orthoxylene, as well as the petrochemicals A-100 and A-150 that are used in the manufacture of paint and chemicals. The refinery has the capacity to refine 70,000 barrels of crude oil per day. Refining sales in 2001 averaged approximately 93,400 barrels per day. The Sarnia Refinery is configured to allow for operational flexibility. In addition to conventional sweet and sour crudes, the refinery is capable of processing sweet synthetic crude oil, which yields a more valuable product mix. A hydrocracker, jet fuel tower and low-sulphur diesel tower further increase the refinery's ability to produce premium-value transportation fuels, distillates and naphtha, and its flexibility to vary the gasoline/distillate ratio. The hydrocracker has a capacity to process approximately 23,300 barrels per day. Additional flexibility in gasoline, octane and petrochemical production is provided by the complementary operations of an alkylation unit with a capacity of 5,400 barrels per day. The petrochemical facilities, which have a capacity of 13,100 barrels per day, produce benzene, toluene, and mixed xylenes, and recover orthoxylene from mixed xylenes, as well as petrochemicals A-100 and A-150. The refinery has a cracking capacity of 40,200 barrels per day from a Houdry Catalytic Cracker ("catcracker") and a hydrocracker. Approximately 40% of the cracking capacity is attributable to the catcracker, which uses older cracking technology. In 2001, The refinery completed planned maintenance on Plant One, which consists of a crude unit, catalytic cracker, alkylation unit, and other treating units. However, the refinery also experienced unplanned outages involving the catcracker, the BTX unit and the vacuum unit. As a result, crude utilization declined 6% to 92% in 2001. The following chart sets out daily crude input, average refinery utilization rates, and cracking capacity utilization of the Sarnia refinery over the last two years.
Sarnia Refinery Capacity 2001 2000 - ------------------------------------ ---- ---- Average daily crude input (barrels per day) 64,200 68,900 Average utilization rate (%)(1) 92 98 Average cracking capacity utilization (%)(2) 88 91
Notes: (1) Based on crude unit capacity and input to crude units. (2) Based on cracking capacity and input to the hydrocracker and catalytic cracker. In 2001 Sunoco entered into an energy supply agreement with TransAlta, under which steam will be supplied to Sunoco's Sarnia Refinery. For more details, see the "Sunoco" section under "Three Year Highlights" in this Annual Information Form. PRINCIPAL PRODUCTS Sales of gasolines and other transportation fuels represented 80% of Sunoco's consolidated revenues and other operating revenues in 2001 compared to 83% in 2000. Set forth below is information on daily sales volumes and percentage of Sunoco's consolidated revenues contributed by product group for the last two years. 24
DAILY SALES VOLUMES 2001 2000 ------------------- ---- ---- (THOUSANDS OF CUBIC % OF SUNOCO'S (THOUSANDS OF % OF SUNOCO'S METRES PER DAY) CONSOLIDATED CUBIC METRES CONSOLIDATED REVENUES PER DAY) REVENUES Transportation fuels Gasoline 5.6 42 5.5 44 Retail (1).................. Other (2)................... 3.1 17 2.8 16 Jet fuel............................ 0.7 4 1.1 5 Other............................... 3.1 17 3.1 18 ----- ---- ----- ---- 12.5 80 12.5 83 ----- ---- ----- ---- Petrochemicals...................... 0.5 4 0.5 4 Heating fuels....................... 0.4 2 0.4 2 Heavy fuel oils..................... 0.8 2 0.6 2 Other............................... 0.6 2 0.6 2 ----- ---- ----- ---- Total Refined Products.............. 14.8 90 14.6 93 ----- ---- ----- ---- Other Non Refined Products.......... - 10 - 7 ----- ---- ----- ---- Total %............................. 100 100 ----- ---- ----- ---- ----- ---- ----- ----
Notes: (1) Excludes joint ventures. (2) Joint ventures PRINCIPAL MARKETS Approximately 59% of Sunoco's total sales volumes are marketed through controlled retail networks, including the Sunoco retail network, joint-venture operated retail stations, and cardlock operations. This controlled network is comprised of: - - 302 Sunoco retail service stations - - 154 Pioneer-operated retail service stations - - 47 UPI-operated service stations and a network of bulk distribution facilities for rural and farm fuels - - 18 Sunoco branded Fleet Fuel Cardlock sites Refined petroleum products (excluding petrochemicals), and natural gas sold to commercial and residential accounts are marketed under several brands, including the Company's Canadian "Sunoco" trademark. Sunoco's other principal trademarks include "Ultra 94" in respect of its premium high octane gasoline, and "Gold Diesel" used in respect of its premium low sulphur diesel product. Approximately 38% of Sunoco's total sales volumes are sold to industrial, commercial, wholesale, and refining customers, primarily in Ontario. Sunoco also supplies industrial and commercial customers in Quebec through long-term arrangements with other regional refiners, or through Group Petrolier Norcan Inc., a 25% Sunoco-owned fuels terminal and product supply business in Montreal. Sunoco markets toluene, mixed xylenes, orthoxylene and petrochemicals, primarily in Canada and the U.S., through Sun Petrochemicals Company. Suncor Energy Marketing Inc. has a 50% interest in Sun Petrochemicals Company, a petrochemical marketing joint venture company, to market products from Sunoco's Sarnia Refinery and a Toledo, Ohio, refinery owned by the joint venture partner. Sun Petrochemicals Company markets petrochemicals used to manufacture plastics, rubber, synthetic fibres, industrial solvents and agricultural products, and as gasoline octane enhancers. All of Sunoco's benzene production is sold directly to other petrochemical manufacturers in Sarnia. 25 Sunoco's share of total refined product sales in its primary market of Ontario is approximately 18% in 2001 compared with approximately 17% in 2000. Transportation fuels accounted for over 84% of Sunoco's total sales volumes in 2001; petrochemicals accounted for 3%. The remaining volumes included other refined products such as heating fuels, heavy oils and liquefied petroleum gases, and were sold to industrial users and resellers. Sunoco supplies refined petroleum products to the Pioneer and UPI joint ventures under exclusive supply agreements. The UPI joint venture expires in 2002, and thereafter will be automatically renewed unless terminated upon 120 days prior written notice. The shareholder agreement between UPI and Sunoco provides that Sunoco has the exclusive right to supply petroleum products to the joint venture as long as Sunoco remains as a shareholder of UPI. No notice of termination has been received or given to date. In addition to refined product sales, Sunoco also markets natural gas to approximately 125,000 commercial and residential customer accounts in Ontario. Margins improved in the natural gas business in 2001 due to a restructuring of customer contracts that locked in fixed price sales to fixed price supply. TRANSPORTATION AND DISTRIBUTION Sunoco uses a variety of transportation modes to deliver products to market, including pipeline, water, rail and road. Sunoco owns and operates petroleum transportation, terminal and dock facilities, including storage facilities and bulk distribution plants in Ontario. The major mode of transporting gasoline, diesel, jet fuel and heating fuels from the Sarnia Refinery to core markets in Ontario is the Sun-Canadian Pipe Line, which is 55% owned by Sunoco and 45% owned by another refiner. The pipeline operates as a private facility for its owners. It serves terminal facilities in Toronto, Hamilton and London, and has a capacity of 126,000 barrels per day (20,000 cubic metres). Sunoco utilized 85% of this capacity in 2001 compared with 84% in 2000. Sunoco also has direct pipeline access to petroleum markets in the Great Lakes region of the United States by way of connection to a pipeline system in Sarnia operated by a U.S.-based refiner. This link to the U.S. allows Sunoco to move products to market or obtain feedstocks/products when market conditions are favourable in the Michigan and Ohio markets. Sunoco believes that its own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet its current and foreseeable needs. CAPITAL EXPENDITURES Sunoco plans to spend approximately $96 million in 2002 compared with $54 million in 2001. Expenditures in 2002 will include funds associated with meeting sulphur-in-gasoline limit regulations at its Sarnia refinery. In 2002 and 2003 Sunoco plans to spend $40 million to meet the new 2005 sulphur-in-gasoline regulated limits. See "Risk / Success Factors Affecting Performance" in the Sunoco section of MD&A and "Risks Specifically Respecting Sunoco" in the "Risk / Success Factors" section of this AIF. ENVIRONMENTAL COMPLIANCE For a description of the impact of environmental protection requirements on Sunoco, please refer to the sections entitled "Outlook" and "Risk/Success Factors Affecting Performance" in the Sunoco section of Management's Discussion and Analysis in Suncor's 2001 Annual Report. Also refer to "Environmental Risks" and "Government Regulation" in the "Risk/Success Factors" section of this AIF. 26 SUNCOR EMPLOYEES The following table shows the distribution of employees among Suncor's three business units, its corporate office and the Stuart Oil Shale Project for the past two years.
YEAR ENDED DECEMBER 31, ----------------- 2001 2000 ----------------- Oil Sands............................................ 2,367 2,057 Natural Gas.......................................... 190 182 Sunoco(1)............................................ 561 590 Stuart Project....................................... - 77 Corporate(2)......................................... 189 137 ----- ----- Total......................................................3,307 3,043 ===== =====
Notes: (1) Excludes joint venture employees. (2) Reflects inclusion of Calgary-based employees providing technical support to the Firebag In-Situ Project, as well as some information technology employees who were previously counted within the individual business units. (3) In addition to Suncor employees, independent contractors supply a range of services to the Company. The Communications, Energy and Paperworkers Union Local 707 represents approximately 1,423 Oil Sands employees. Suncor entered into a three-year collective agreement with the union effective May 1, 2001. Management believes Suncor's positive working relationship with the union will continue. Employee associations represent approximately 170 Sunoco Sarnia refinery and Sun-Canadian Pipe Line Company employees. In March 2001, Sunoco and the Sarnia employee association signed a one-year agreement that will be renegotiated in 2002. Sunoco management believes Sunoco's positive working relationship with this association will continue and a new agreement should be reached. The agreement with the employee association of Sun-Canadian Pipe Line Company was signed in 1993, and it is renewed automatically each year unless terminated by written notice by either party at least 60 days prior to the anniversary date of the agreement. No notice under such agreement has been received or given to date. Sunoco management believes Sunoco's positive working relationship with this association will continue and the agreement will be automatically renewed on its anniversary. RISK/SUCCESS FACTORS VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES. Suncor's future financial performance is closely linked to oil prices, and to a lesser extent natural gas prices. The price of these commodities can be influenced by global and regional supply and demand factors. Worldwide economic growth, political developments, compliance or non-compliance with quotas imposed upon members of the Organization of Petroleum Exporting Countries and weather, among other things, can affect world oil supply and demand. Natural gas prices realized by Suncor are affected primarily by North American supply and demand and by prices of alternate sources of energy. All of these factors are beyond Suncor's control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for sour crude. In 2001, the heavy-light differential widened and reduced earnings. Management believes the differential will trend toward more historical levels in 2002 if the demand for heavy oil increases as anticipated. Oil and natural gas 27 prices have fluctuated widely in recent years and Suncor expects continued volatility and uncertainty in crude oil and natural gas prices. A prolonged period of low crude oil prices could affect the value of Suncor's crude oil and gas properties and the level of spending on development projects, and could result in curtailment of production at some properties, and accordingly could have an adverse impact on Suncor's financial condition and liquidity and results of operations. Suncor cannot control the factors that influence supply and demand or the prices of crude oil or natural gas. Suncor cannot control the prices of crude oil or natural gas, or currency exchange rates. However, the Company has a hedging program that fixes the price of crude oil, and periodically, natural gas, and the associated exchange for a percentage of Suncor's total production volume. Suncor's objective is to lock-in prices on a portion of its future production today to reduce exposure to market volatility and ensure the Company's ability to finance growth. If an operational upset occurred that reduced or eliminated crude oil and/or natural gas production for a period of time, Suncor would be required to continue to make payments under its hedging program if the actual price was higher than the price hedged. For particulars of Suncor's hedging position as of year-end 2001, see Note 17 of Suncor's consolidated financial statements. Suncor conducts an assessment of the carrying value of its assets to the extent required by Canadian general accepted accounting principles ("GAAP"). If crude oil and natural gas prices decline, the carrying value of Suncor's assets could be subject to downward revisions, and Suncor's earnings could be adversely affected. RISK FACTORS RELATED TO FIREBAG AND VOYAGEUR PROJECTS. There are certain risks associated with the execution of the proposed Firebag In-Situ Oil Sands Project and Voyageur, including: regulatory approvals, schedule, resources and costs, including the availability and cost of materials, equipment and qualified labour; the impact of general economic, business and market conditions; the impact of weather conditions; Suncor's ability to finance Oil Sands growth if commodity prices were to stay at low levels for an extended period; the impact of new entrants to the oil sands business which could take the form of competition for skilled people, increased demands on the Fort McMurray, Alberta infrastructure (for example, housing, roads and schools), or price competition for products sold into the marketplace; the potential ceiling on the demand for synthetic crude oil; and the effect of changing standards of government regulation and public expectations in relation to the impact of oil sands development on the environment. The commissioning and integration of new facilities with the existing asset base could cause delays in achieving targeted production capacity. Suncor management believes the planned increases in Oil Sands production through these projects present issues that require prudent risk management. RISKS ASSOCIATED WITH INTEGRATION OF PROJECT MILLENNIUM WITH BASE PLANT OPERATIONS. With Project Millennium commissioning complete by year-end 2001, the main risks to final Project Millennium execution are associated with integration of the new facilities with the existing asset base, particularly during the winter months where risks associated with weather are increased. These risks could cause unforeseen outages and costs, and delays in achieving full utilization of the combined production capacity of 225,000 barrels per day. INCREASED DEPENDENCE ON OIL SANDS BUSINESS. The Company's significant capital commitment to further its growth projects at Oil Sands, including the Firebag In-Situ Oil Sands Project, and Voyageur if approved, may require Suncor to forego investment opportunities in other segments of its operations. The completion of Project Millennium, and the other future projects to increase production at Oil Sands, will substantially increase the Company's dependence on the Oil Sands segment of its business. For example, assuming achievement of Oil Sands' 2002 production target of 210,000 barrels per day, the Oil Sands business will account for approximately 86% of Suncor's upstream production in 2002 compared to 79% in 2001 and 74% in 2000. RISKS ASSOCIATED WITH IN-SITU EXTRACTION. Current steam-assisted gravity drainage (SAGD) technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels to produce steam. Although there have been a number of SAGD technology 28 pilot projects and several commercial scale projects are under development and are scheduled to be on production by the end of 2002, commercial application of this technology is not yet commonplace. COMPETITION. The petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of crude oil and gas interests, and the refining, distribution and marketing of petroleum products and chemicals. Suncor competes in virtually every aspect of its business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. Suncor offers custom blends of synthetic crude oil to meet specific customer demands. Suncor believes that the competition for its custom blended synthetic crude oil production is Canadian conventional and synthetic sweet and sour crude oil. A number of other companies have entered or have indicated they are planning to enter the oil sands business and begin production of bitumen and synthetic crude oil, or expand existing operations. If all announced competing projects were to be built, they could quadruple Canada's production of bitumen and upgraded synthetic crude oil to more than two and half million barrels (400,000 cubic metres) per day by the end of the decade. The recent trend toward industry consolidation has created more competitors with financial capacity who may enter into similar and competing oil sands businesses. Expansion of existing operations and development of new projects could materially increase the supply of bitumen and synthetic crude oil and other competing crude oil products in the marketplace. Depending on the levels of future demand, increased supplies could have a negative impact on prices. In the western Canadian diesel market demand and supply can fluctuate. Currently there is excess supply of diesel fuel and Suncor expects the market could be impacted by this excess supply and have a negative impact on margins. Margins for diesel are typically higher than the margins for synthetic and conventional crude oil. The above noted expansion plans of Suncor's competitors could also result in an increase in the supply of diesel and further weakening of margins. Historically, the industry-wide oversupply of refined petroleum products and the overabundance of retail outlets have kept pressure on downstream margins. Management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, as Suncor's downstream business unit, Sunoco, participates in new product markets, such as natural gas, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations. NEED TO REPLACE CONVENTIONAL NATURAL GAS RESERVES. The future natural gas reserves and production of the Company's NG business unit and, therefore, both NG's cash flow from such production and Suncor's ability to maintain an internal hedge against growing consumption of natural gas in its Oil Sands and Sunoco operations, are highly dependent on its success in discovering or acquiring additional reserves and exploiting its current reserve base. Without natural gas reserve additions through exploration and development or acquisition activities, NG's conventional natural gas reserves and production will decline over time as reserves are depleted. For example, in 2001, Suncor's natural gas average reservoir decline rates were in the 28% range, consistent with industry experience. Decline rates will vary with the nature of the reservoir, life-cycle of the well, and other factors. Therefore past decline rates are not necessarily indicative of future performance. Exploring for, developing and acquiring reserves is highly capital intensive. To the extent cash flow from operations is insufficient to generate sufficient capital and external sources of capital become limited or unavailable, NG's ability to make the necessary capital investments to maintain and expand its conventional natural gas reserves could be impaired. In addition, NG's long term performance is dependent on its ability to consistently and competitively find and develop low cost, high-quality reserves that can be economically brought on stream. Market demand for land and services can also increase or decrease finding and development costs. There can be no assurance that Suncor will be able to find and develop or acquire additional reserves to replace production at acceptable costs. RISKS RELATED TO COALBED METHANE. Coalbed Methane (CBM) exploration is being undertaken by Suncor in Canada and the U.S. through a wholly owned subsidiary, Suncor Energy (Natural Gas) America Inc. The identification of gas in coals is necessary but not sufficient for establishing commercial success. 29 Effective production technology, water handling, well productivity, requirement for large land blocks, and a pilot production period are risk elements unique to CBM. In Canada, CBM as a gas resource has not yet been proven commercial, and bears the additional risk that significant commercial production may require new technology or only be available in limited areas or at higher long term gas prices than currently exist. CBM is a commercial gas resource in the U.S.. The risks associated with CBM activities in the U.S. vary by geographic region but can include: constraints on land access from federal, state and individual land holders; local opposition to well drilling and CBM development; high costs of treating water produced with CBM gas; limited regional pipeline exit capacity; and strong competition for mineral leases and services. The regulatory framework and stakeholder environment varies by region. The physical operation of drilling and ultimately producing gas in a location distant from Suncor's key management presents risks of inadequate oversight of operations. Business activity in the U.S. has different political risk than in Canada, and is conducted in an environment where litigation and legal risk are more prevalent and substantial. OPERATING HAZARDS AND OTHER UNCERTAINTIES. Each of Suncor's three principal business units, Oil Sands, NG and Sunoco, require high levels of investment and have particular economic risks and opportunities. Generally, Suncor's operations are subject to hazards and risks such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts and oil spills, any of which can cause personal injury, damage to property, equipment and the environment, as well as interrupt operations. In addition, all of Suncor's operations are subject to all of the risks normally incident to the transportation, processing and storing of crude oil, natural gas and other related products. At Oil Sands, mining oil sand, extracting bitumen from the oil sand, and upgrading bitumen into synthetic crude oil and other products, involve particular risks and uncertainties. Oil Sands is susceptible to loss of production, slowdowns, or restrictions on its ability to produce higher value products due to the interdependence of its component systems. Severe climatic conditions at Oil Sands can cause reduced production and in some situations result in higher costs. While there is no finding cost associated with oil sands resources, the costs associated with production, including mine development and drilling of wells for SAGD operations, and the costs associated with upgrading bitumen into synthetic crude oil, can entail significant capital outlays. The costs associated with synthetic crude oil production at Oil Sands are largely fixed and, as a result, operating costs per unit are largely dependent on levels of production. Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Certain aboriginal peoples have filed a claim against the government of Canada, certain governmental entities and the Regional Municipality of Wood Buffalo (which includes the city of Fort McMurray, Alberta), claiming, among other things, a declaration that the plaintiffs have aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which Oil Sands and most of the other oil sands operations in Alberta are situated. To Suncor's knowledge the aboriginal peoples have made no claims against Suncor and Suncor is unable to assess the effect, if any, the claim would have on its Oil Sands operations. In Suncor's NG business unit, the risks and uncertainties associated with the exploration for, and the development, production, transportation and storage of crude oil, natural gas and natural gas liquids should not be underestimated or viewed as predictable. NG's operations are subject to all of the risks normally incident to drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution, and other environmental risks. Suncor's downstream business unit, Sunoco, is subject to all of the risks normally incident to the operation of a refinery, terminals and other distribution facilities, as well as service stations, including loss of product or slowdowns due to equipment failures or other accidents. Although Suncor maintains a risk management program, including an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. 30 Losses resulting from the occurrence of these risks could have a material adverse impact on Suncor. Under the Company's business interruption insurance coverage, the Company would bear the first $U.S.260 million of any loss arising from a future insured incident at its Oil Sands operations. In addition, there are risks associated with growth projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies, such as the Firebag In-Situ Oil Sands Project, cannot be assured. There are also inherent risks, including political and foreign exchange risk, in investing in business ventures internationally. To date, Suncor does not have material international investments but is investigating coalbed methane opportunities in the United States. However, export sales in 2001 represented 15% of Suncor's 2001 consolidated revenue (2000 - 14%). INTEREST RATE RISK. Suncor is exposed to fluctuations in short-term Canadian interest rates as a result of the use of floating rate debt. Suncor maintains a substantial portion of its debt capacity in revolving, floating rate bank facilities and commercial paper, with the remainder issued in fixed rate borrowings. To minimize its exposure to interest rate fluctuations, Suncor occasionally enters into interest rate swap agreements and exchange contracts to either effectively fix the interest rate on floating rate debt or to float the interest rate on fixed rate debt. For more details, see the "Liquidity and Capital Resources" section of MD&A. EXCHANGE RATE FLUCTUATIONS. Suncor's consolidated financial statements are presented in Canadian dollars. Results of operations are affected by the exchange rates between the Canadian dollar and the U.S. dollar. These exchange rates have varied substantially in the last five years. A substantial portion of Suncor's revenue is received by reference to U.S. dollar denominated prices. Oil prices are generally set in U.S. dollars, while Suncor's sales of refined products are primarily in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollar may therefore give rise to foreign currency exposure, either favorable or unfavorable, creating another element of uncertainty. In the future, the strength of the Canadian dollar relative to foreign currencies could create additional uncertainties for Suncor as it pursues its international growth plans. ENVIRONMENTAL RISKS. Environmental legislation affects nearly all aspects of Suncor's operations. These regulatory regimes are laws of general application that apply to Suncor in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require Suncor to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are required before initiating most new major projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, Suncor expects future changes to environmental legislation will likely impose further requirements on companies operating in the energy industry. Some of the issues include the possible cumulative impacts of oil sands development in the Athabasca region; storage, treatment, and disposal of hazardous or industrial waste, the need to reduce or stabilize various emissions, issues relating to global climate change including the potential impacts of government regulation; land reclamation and restoration; Great Lakes water quality; and reformulated gasoline to support lower vehicle emissions. Changes in environmental legislation could have a potentially adverse effect on Suncor from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on Suncor. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties, liability for clean up costs and damages and the loss of important permits. 31 Suncor is required to and has posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced ($15 million as at December 31, 2001) as security for the estimated cost of its reclamation activity on Leases 86 and 17, and the Steepbank Mine. For Project Millennium, Suncor has posted an irrevocable letter of credit equal to approximately $26 million, representing security for the estimated cost of reclamation activities relating to Project Millennium up to the end of January, 2002. UNCERTAINTY OF RESERVE AND RESOURCE ESTIMATES. The reserve data and resource estimates for Suncor's Oil Sands and NG business units, included in Suncor's Annual Information Form, represent estimates only. There are numerous uncertainties inherent in estimating quantities and quality of these proved and probable reserves and other resources, including many factors beyond the control of Suncor. In general, estimates of economically recoverable reserves are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. The accuracy of any reserve estimate is a matter of engineering interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time. In the Oil Sands business unit, reserve estimates are based upon a geological assessment, including drilling and laboratory tests, and also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints. The Firebag reserves and resource estimates are based upon a geological assessment based upon the data gathered from evaluation drilling, the testing of core samples and seismic operations. In the NG business unit, reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. For these reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, and in NG the classification of such reserves based on risk of recovery prepared by different engineers or by the same engineers at different times, may vary substantially. At Oil Sands, the independent audit does not take into account the economic aspects of future reserves. Suncor's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. Certain information included in this annual information form to describe Suncor's reserves and resources, such as "probable reserves" and "resources", is prohibited in filings with the United States Securities and Exchange Commission by U.S. companies. The differences between Canadian and U.S. standards of reporting reserves and resources may make it difficult to compare Suncor's reserve and resource information with the reserve information of companies subject to the U.S. standards of reporting. RISKS SPECIFICALLY RESPECTING SUNOCO. Sunoco's operations are sensitive to wholesale and retail margins for its refined products, including gasoline. Margin volatility is influenced by overall marketplace competitiveness, weather, the cost of crude oil (See "Volatility of Crude Oil and Natural Gas Prices.") and fluctuations in supply and demand for refined products. Sunoco expects that margin and price volatility and overall marketplace competitiveness will continue. In 1999, the Canadian government passed legislation limiting sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. The Canadian refining industry faces significant capital spending to construct sulphur removal facilities to meet these requirements. In 2001 Sunoco finalized an investment plan to meet those limits. Capital spending to achieve compliance is expected to be approximately $40 million, and will involve the addition of a new desulphurization unit. Construction of the unit is planned for 2002 and 2003. The federal government has proposed a regulation under the CANADIAN ENVIRONMENTAL PROTECTION ACT that will limit the level of sulphur in diesel fuel used in on-road vehicles to a maximum of 15 ppm. The proposed regulation is expected to come into effect in June 2006 for producers and importers, and in September 2006 for sellers. Regulations with respect to off-road diesel and light fuel oil are also expected. Sunoco continues to examine strategic options to comply with the pending regulations. Actual capital required to meet the new standards is subject to further development of such regulations and 32 strategic assessment by Sunoco. The cost to comply with the sulphur-in-diesel limits could be significant but is not currently expected to place the Company at a competitive disadvantage. LABOUR RELATIONS. Suncor's hourly employees at its Oil Sands facility near Fort McMurray and its Sarnia refinery are represented by a labour union and an employee association, respectively. Suncor's collective agreement with the Communications, Energy and Paperworkers Union Local 707 at Oil Sands was renegotiated in May 2001 for a three-year term. Any work interruptions involving Suncor's employees, or contract trades utilized in its growth projects, could materially and adversely affect Suncor's business and financial position. GOVERNMENTAL REGULATION. The oil and gas industry in Canada, including the oil sands industry and the downstream segment of the Company, operates under federal, provincial and municipal legislation. This industry is also subject to regulation and intervention by governments in such matters as land tenure, royalties, government fees, production rates, environmental protection controls, the export of crude oil, natural gas and other products, the awarding or acquisition of exploration and production, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights. Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other things. In addition, regulatory approvals may be subject to conditions including security deposit obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment or restructuring of projects and increased costs, all of which could negatively affect future earnings and cash flow. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase Suncor's costs and have a material adverse affect on its financial condition. 33 SELECTED CONSOLIDATED FINANCIAL INFORMATION SELECTED CONSOLIDATED FINANCIAL INFORMATION The following selected consolidated financial information for each of the years in the three-year period ended December 31, 2001 is derived from Suncor's consolidated financial statements. The consolidated financial statements for each of the years in the three-year period ended December 31, 2001 have been audited by PricewaterhouseCoopers LLP, Chartered Accountants. Suncor's 2001 audited consolidated financial statements accompanied by the audit report of PricewaterhouseCoopers LLP for each of the years in the three-year period ended December 31, 2001. The information set forth below should be read in conjunction with the MD&A and Suncor's consolidated comparative financial statements and related notes.
YEAR ENDED DECEMBER 31,(1) ---------------------------- 2001 2000 1999 ---- ---- ---- ($ MILLIONS EXCEPT PER SHARE AMOUNTS) Revenues................................................. 3,995 3,388 2,387 Net earnings............................................. 388 377 186 Per common share(1) (undiluted).......................... 1.63 1.58 0.74 Per common share(1) (diluted)............................ 1.61 1.57 0.73 Cash flow provided from operations....................... 831 958 591 Per common share(1)...................................... 3.52 4.11 2.51 Capital and exploration expenditures..................... 1,678 1,998 1,350
AS AT DECEMBER 31, --------------------------- 2001 2000 1999 ---- ---- ---- ($ MILLION) Total assets.............................................. 8,094 6,833 5,176 Long-term borrowings(2)................................... 3,113 2,193 1,307 Accrued liabilities and other(3) 251 252 236 Common shareholders' equity(4)............................ 2,263 1,958 1,594
Notes: (1) Per share amounts for all years reflect a two-for-one share split in 2000 and payments on the preferred securities issued in 1999. (2) Includes current portion. (3) See Notes 12 and 13 to Suncor's 2001 Consolidated Financial Statements, which Notes are incorporated by reference herein. (4) Excludes Preferred Securities issued in 1999. See Dividend Policy and Record. DIVIDEND POLICY AND RECORD Suncor's Board of Directors has established a policy of paying dividends on a quarterly basis. This policy is reviewed from time to time in light of Suncor's financial position, its financing requirements for growth, its cash flow and other factors considered relevant by Suncor's Board of Directors. A dividend of $0.085 per common share for the first quarter of 2002 has been declared, payable on March 25, 2002 to shareholders of record on March 15, 2002. 34 During 1999, the Company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of U.S.$162.5 million of 9.125% preferred securities, the proceeds of which totalled Canadian $507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debt of the Company, due in 2048 and redeemable at the Company's option on or after March 15, 2004. Subject to certain conditions, the Company has the right to defer payment of interest on the securities for up to 20 consecutive quarterly periods. Deferred interest and principal amounts are payable in cash, or, at the option of the Company, from the proceeds on the sale of equity securities of the Company delivered to the trustee of the preferred securities. For accounting purposes, the preferred securities are classified as share capital in the consolidated balance sheet and the interest distributions thereon, net of income taxes, are classified as dividends. The following table sets forth the per share amount of dividends paid by Suncor during the last three years.
YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 1999 ---- ---- ---- Common Shares Cash dividends(1).................................. $0.34 $0.34 $0.34 Preferred Securities Cash interest distributions........................ $0.21 $0.21 $0.17 Dividends paid in common shares.................... -- -- --
Note: (1) Per share amounts for 2000 and 1999 have been adjusted to reflect a two-for-one share split in 2000. FUTURE COMMITMENTS TO BUY, SELL, EXCHANGE OR TRANSPORT CRUDE OIL AND NATURAL GAS In order to ensure continued availability of, and access to, transportation facilities for the crude oil and natural gas products of its Oil Sands and Natural Gas business units, the Company has entered into long-term contracts for pipeline capacity on various third party systems. The Company's Oil Sands business unit has entered into a long-term commitment with Enbridge for the transportation of sour crude oil and bitumen from Suncor's oil sands plant near Ft. McMurray, Alberta, to Hardisty, Alberta. Particulars of that commitment are described under the heading "Operations" in the "Oil Sands" section of this Annual Information Form. Natural gas product pipeline commitments are described in the following table: 35
- -------------------------------------------------------------------------------------------------------------- AGGREGATE - -------------------------------------------------------------------------------------------------------------- NATURE OF COMMITMENTS TERM VOLUME PRICE/COST PRICE PER THOUSAND (MMCF/DAY) CUBIC FEET - -------------------------------------------------------------------------------------------------------------- ($ MILLIONS) - -------------------------------------------------------------------------------------------------------------- Natural gas pipeline commitments: - -------------------------------------------------------------------------------------------------------------- Nova 1998-2008 ** 30 $0.17 - -------------------------------------------------------------------------------------------------------------- Westcoast Energy 2001-2006 27 9 $0.23 - -------------------------------------------------------------------------------------------------------------- Foothills 1997-2003 16 1 $0.08 - -------------------------------------------------------------------------------------------------------------- Northern Border 1997-2003 14 5 $0.52 - -------------------------------------------------------------------------------------------------------------- Alberta Natural Gas 1991-2008 41 8 $0.07 - -------------------------------------------------------------------------------------------------------------- Pacific Gas Transmission 1995-2023 40 164 $0.49 - --------------------------------------------------------------------------------------------------------------
** volume varies on an annual basis The Company's Natural Gas business has entered into numerous natural gas purchase and sale commitments, aggregating 90 mmcf/day and 180 mmcf/day, respectively. Purchase commitment terms vary from one to three years and pricing varies, representing a combination of fixed and index-based pricing. Sales commitments consist of both short- and long- term contracts ranging from one to eight years in duration, with varying pricing generally based on a combination of fixed and index-based terms. Oil Sands has also entered into long-term contracts to sell crude oil products to customers, some of which are described under the heading, "Revenues from Synthetic Crude Oil and Diesel", in the "Oil Sands" section of this Annual Information Form. In addition, the Company enters into crude oil and foreign currency swap and option contract to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable U.S./Canadian dollar exchange rates. For further particulars of these hedging arrangements, see the information under the heading "Hedging", under "Risk/Success Factors Affecting Performance" in the "Corporate" section of the Company's MD&A, incorporated by reference herein, and Note 17 to Suncor's 2001 Consolidated Financial Statements, which note is incorporated by reference herein. Also see Note 14 to Suncor's 2001 Consolidated Financial Statements, which note is incorporated by reference herein, for a further description of the Company's operating commitments for 2002 and subsequent years. MANAGEMENT'S DISCUSSION AND ANALYSIS Suncor's MD&A is incorporated by reference into and forms an integral part of this Annual Information Form, and should be read in conjunction with the consolidated comparative financial statements and the notes thereto. MARKET FOR THE SECURITIES OF THE ISSUER The common shares of Suncor are listed on The Toronto Stock Exchange in Canada, and on the New York Stock Exchange in the United States. To the best of management's knowledge, approximately 50% of Suncor's common shares are beneficially held by residents of the United States. Suncor's 9.05% preferred securities are listed on The Toronto Stock Exchange in Canada, and Suncor's 9.125% preferred securities are listed on the New York Stock Exchange in the United States. 36 DIRECTORS AND OFFICERS As of the date hereof, Suncor's Board of Directors is comprised of eleven directors. The term of office of each director is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed. The Board of Directors is required to have, and has, an Audit Committee. The Board of Directors also has a Board Policy, Strategy Review and Governance Committee, a Human Resources and Compensation Committee, and an Environment, Health and Safety Committee. The following table sets out certain information with respect to Suncor's directors.
VOTING SECURITIES OF PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY OR EMPLOYMENT, AND OWNED OR OVER WHICH MAJOR POSITIONS AND CONTROL OR DIRECTION NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2002(1) - ---------------------------- -------------------- ----------------------- ---------------------- Mel Benson(2) (5) April 19, 2000 to Management Services 2,565 Common Shares Calgary, Alberta Present Consultant 367 Deferred Share Units(3) Brian A. Canfield(2)(4) November 10, 1995 Chairman 6,000 Common Shares Point Roberts, Washington to Present TELUS Corporation (a telecommunications 3,770 Deferred Share company) Units(3) Bryan P. Davies(2)(5) January 28, 1991 Senior Vice 6,200 Common Shares Etobicoke, Ontario to April 23, 1996 President, Regulatory Affairs, Royal Bank 1,644 Deferred Share April 19, 2000 to of Canada (a Units(3) Present chartered banking institution) John T. Ferguson(5)(6) November 10, 1995 Chairman, Princeton 8,374 Common Shares Edmonton, Alberta to Present Developments Ltd. (a real estate 1,955 Deferred Share development company), Units(3) Chair of the Board, TransAlta Corporation (an electric utility company)
37
VOTING SECURITIES OF PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY OR EMPLOYMENT, AND OWNED OR OVER WHICH MAJOR POSITIONS AND CONTROL OR DIRECTION NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2002(1) - ---------------------------- -------------------- ----------------------- ---------------------- Richard L. George(6) February 1, 1991 President and Chief 99,277 Common Shares Calgary, Alberta to Present Executive Officer, Suncor Energy Inc.(7) Poul Hansen(2)(5)(9) April 23, 1996 to Chairman and General 7,291 Common Shares Vancouver, British Columbia Present Manager, Sperling Hansen Associates Inc. (an environmental engineering consulting company) John R. Huff(4)(6) January 30, 1998 Chairman and Chief 10,354 Common Shares Houston, Texas to Present Executive Officer, Oceaneering 4,047 Deferred Share International, Inc. Units(3) (an oilfield services company) Robert W. Korthals(5)(6)(8) April 23, 1996 to Corporate Director 8,000 Common Shares Toronto, Ontario Present 3,343 Deferred Share Units (3) M. Ann McCaig(2)(4) October 1, 1995 to President, VPI 5,144 Common Shares Calgary, Alberta Present Investments Ltd. (a private investment 4,227 Deferred Share holding company) Units(3) JR Shaw(4)(6) January 30, 1998 Executive Chair, Shaw 41,600 Common Shares Calgary, Alberta to Present Communications Inc. (a diversified 6,234 Deferred Share communications Units(3) company); Chairman of the Board of Directors of Suncor Energy Inc.
38
VOTING SECURITIES OF PRINCIPAL OCCUPATION SUNCOR BENEFICIALLY OR EMPLOYMENT, AND OWNED OR OVER WHICH MAJOR POSITIONS AND CONTROL OR DIRECTION NAME AND MUNICIPALITY OF PERIODS OF SERVICE OFFICES IN THE LAST IS EXERCISED AS AT RESIDENCE AS A DIRECTOR FIVE YEARS FEBRUARY 28, 2002(1) - ---------------------------- -------------------- ----------------------- ---------------------- W. Robert Wyman(4)(6)(9) November 25, 1987 Retired Chairman of 32,400 Common Shares West Vancouver, British to Present the Board of Columbia Directors of Suncor 4,138 Deferred Share Energy Inc. Units(3)
Notes: (1) The information relating to holdings of Common Shares, not being within the knowledge of Suncor, has been furnished by the respective nominees individually. Fractional Common Shares have been excluded from the numbers shown. Certain of the Common Shares held by Mr. George, Mr. Hansen and Mr. Shaw are held jointly with their respective spouses. The number of Common Shares held by Mr. George includes 82,486 Common Shares over which he exercises control or direction but which are beneficially owned by members of his family. Certain Common Shares held by Mr. Benson (400) and Mr. Shaw (1,000) are beneficially owned by their respective spouses, but they respectively exercise control or direction over such shares. (2) Member of the Environment, Health and Safety Committee. (3) Deferred Share Units (DSU's) are not voting securities but are included for informational purposes as they are Common Share equivalents. (4) Member of the Human Resources and Compensation Committee. (5) Member of the Audit Committee. (6) Member of the Board Policy, Strategy Review and Governance Committee. (7) Mr. George also serves as director and/or officer of certain subsidiaries of Suncor. (8) In 1998, Mr. Korthals was a director of Anvil Range Mining Corporation, which sought protection under the COMPANIES CREDITORS ARRANGEMENT ACT (Canada). (9) Retiring from the Board in April 2002. Each of the nominees has been engaged in the principal occupation (or in other executive capacities for the same, affiliated or predecessor entities) indicated above for the past five years, except for Mr. Benson, who from 1996 to 2000 was the Senior Operations Advisor, African Development, Exxon Co. International, Mr. Shaw, who became the Chairman of the Board of Suncor in 2001 and Mr. Wyman, who in 1999 and prior thereto was Vice Chairman of the Board of Directors of Fletcher Challenge Canada Limited. The following are officers of the Corporation. Except where otherwise indicated, the persons named in the table below held the offices set out opposite their respective names as at December 31, 2001 and as of the date hereof. 39
NAME AND MUNICIPALITY OF RESIDENCE OFFICE(1) ---------------------------------- --------- JR SHAW..............................................Chairman of the Board Calgary, Alberta RICHARD L. GEORGE....................................President and Chief Executive Officer Calgary, Alberta M.M. (MIKE) ASHAR....................................Executive Vice President, Oil Sands Fort McMurray, Alberta DAVID W. BYLER.......................................Executive Vice President, Natural Gas and Renewable M.D. of Rockyview, Alberta Energy MICHAEL W. O'BRIEN...................................Executive Vice President, Corporate Development and Canmore, Alberta Chief Financial Officer THOMAS L. RYLEY......................................Executive Vice President, Sunoco Toronto, Ontario TERRENCE J. HOPWOOD..................................Senior Vice President and General Counsel Calgary, Alberta SUE LEE..............................................Senior Vice President, Human Resources and Calgary, Alberta Communications KEVIN NABHOLZ Senior Vice President, Major Projects Fort McMurray, Alberta J. KENNETH ALLEY.....................................Vice.President, Finance Calgary, Alberta JANICE B. ODEGAARD...................................Vice.President, Associate General Counsel and Calgary, Alberta Corporate Secretary
Note: (1) The principal occupation of each officer is the specified office with Suncor except Mr. Shaw, who is also Executive Chair of Shaw Communications Inc. All of the foregoing officers of the Company have, for the past five years, been actively engaged as executives or employees of Suncor or its affiliates, except Mr. Shaw, as described in Note (1) to the above table. The percentage of Common Shares of Suncor owned beneficially, directly or indirectly, or over which control or direction is exercised by Suncor's directors and senior officers, as a group, is less than 1%. ADDITIONAL INFORMATION Copies of the documents set out below may be obtained without charge by any person upon request to the Company at 112 - 4 Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, by e-mail request to info@suncor.com. ---------------- (i) The current Suncor Annual Information Form together with any pertinent information incorporated by reference therein; (ii) The current Suncor comparative financial statements for the most recently completed financial 40 year and the report of the auditors relating thereto, together with any subsequent interim financial statements; (iii) Suncor's management proxy circular in respect of its most recent annual meeting of shareholders that involved the election of directors; and (iv) Any other documents incorporated by reference into Suncor's most recent preliminary short form prospectus or short form prospectus if securities of Suncor are in the course of distribution pursuant to such documents. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Suncor's securities, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in Suncor's most recent management proxy circular for its most recent annual meeting of its shareholders that involved the election of directors. Additional financial information is provided in Suncor's comparative financial statements for its most recently completed financial year. UNDERTAKING AND CONSENT TO SERVICE OF PROCESS A. UNDERTAKING Suncor Energy Inc. (the "Registrant") undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the Securities and Exchange Commission ("SEC"), and to furnish promptly, when requested to do so by the SEC staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises or transactions in said securities. B. CONSENT TO SERVICE OF PROCESS The Registrant has filed previously with the SEC a Form F-X in connection with the Common Shares. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SUNCOR ENERGY INC. Date: March 28, 2002 BY: "DAVID W. BYLER" ----------------------------------- DAVID W. BYLER Executive Vice President, Natural Gas and Renewable Energy EXHIBIT INDEX
EXHIBIT DESCRIPTION OF EXHIBIT - ------------- ---------------------- EXHIBIT 1 Reconciliation to U.S. GAAP EXHIBIT 2 Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2001 EXHIBIT 3 Management's Discussion and Analysis for the fiscal year ended December 31, 2001, dated February 28, 2002 EXHIBIT 4 Excerpt from pages 69 and 70 of Suncor Energy Inc.'s 2001 Annual Report to Shareholders EXHIBIT 5 Consent of PricewaterhouseCoopers LLP EXHIBIT 6 Consent of Gilbert Laustsen Jung Associates Ltd.
EX-1 3 a2075015zex-1.txt EXHIBIT 1 SUNCOR ENERGY INC. 2001 RECONCILIATION OF RESULTS FROM CANADIAN GAAP TO U.S. GAAP (ALL FIGURES ARE IN CANADIAN DOLLARS) CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES The consolidated financial statements of Suncor Energy Inc. have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The measurement adjustments under U.S. GAAP result in changes to the Consolidated Statements of Earnings and Consolidated Balance Sheets of the company as follows:
- ------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 - ------------------------------------------------------------------------------------------------------------------------------- ($ millions) CDN US CDN US CDN US - ------------------------------------------------------------------------------------------------------------------------------- REVENUES Sales & other operating revenues (1) (8) 3,990 4,077 3,385 3,481 2,383 2,448 Interest 5 5 3 3 4 4 Other income (8) - 20 - - - - - ------------------------------------------------------------------------------------------------------------------------------- 3,995 4,102 3,388 3,484 2,387 2,387 - ------------------------------------------------------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products 1,391 1,391 807 807 519 519 Operating, selling and general (1) (2) (8) 1,010 1,148 918 1,036 774 791 Exploration 22 22 53 53 40 40 Royalties 134 134 199 199 99 99 Taxes other than income taxes 367 367 361 361 334 334 Depreciation, depletion & amortization (3) 360 365 365 372 318 318 Gain on disposal of assets (7) (7) (148) (148) (34) (34) Write down of oil shale assets (4) 48 (71) 125 244 - - Restructuring (2) (2) 65 65 - - Start-up expenses- Project Millennium 141 141 15 14 - 1 - Other (5) - (17) - (13) - 31 Interest (3) 18 62 8 40 26 59 - ------------------------------------------------------------------------------------------------------------------------------- 3,482 3,533 2,768 3,030 2,076 2,158 - ------------------------------------------------------------------------------------------------------------------------------- 513 569 620 454 311 294 EARNINGS BEFORE INCOME TAXES - ------------------------------------------------------------------------------------------------------------------------------- PROVISION FOR (RECOVERY OF) INCOME TAXES Current (8) 4 (7) 45 45 29 29 Future (3) (4) (5) (6) (8) 121 157 198 138 96 87 - ------------------------------------------------------------------------------------------------------------------------------- 125 150 243 183 125 116 - ------------------------------------------------------------------------------------------------------------------------------- 388 419 377 271 186 178 NET EARNINGS Dividends on preferred securities (3) (26) - (26) - (22) - - ------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS 362 419 351 271 164 178 PER COMMON SHARE NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS Basic 1.63 1.88 1.58 1.22 0.74 0.81 Diluted 1.61 1.86 1.57 1.21 0.73 0.80 - ------------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME, NET OF TAX Minimum pension liability (7) N/A (28) N/A (2) N/A 6 Hedging activities (8) N/A 29 N/A - N/A - - ------------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME N/A 1 N/A (2) N/A 6 - -------------------------------------------------------------------------------------------------------------------------------
* Per share calculations, for both current and prior years, reflect a two-for-one split of the company' common shares during 2000.
AS AT as at DECEMBER 31, 2001 December 31, 2000 ($ MILLIONS) ($ millions) AS U.S. As U.S. REPORTED GAAP reported GAAP ------------ ------------ ------------ ------------ Current assets (8) 622 694 665 666 Capital assets, net (3) 7,141 7,174 5,883 5,768 Deferred charges and other (3) (7) 199 210 166 173 Future income taxes (3) (7) 132 159 119 125 ------------ ------------ ------------ ------------ Total assets 8,094 8,237 6,833 6,732 ============ ============ ============ ============ Current liabilities (8) 773 806 837 837 Long-term borrowings (3) 3,113 3,649 2,192 2,716 Accrued liabilities and other (2) (7) 251 336 252 277 Future income taxes (3) 1,180 1,220 1,080 1,042 Equity: Share capital and retained earnings (3) 2,777 2,225 2,472 1,862 Accumulated other comprehensive Income (7) (8) N/A 1 N/A (2) ------------ ------------ ------------ ------------ 2,777 2,226 2,472 1,860 ------------ ------------ ------------ ------------ Total liabilities and shareholders' equity 8,094 8,237 6,833 6,732 ============ ============ ============ ============
(1) Under U.S. GAAP (EITF 00 - 10, "Accounting for Shipping and Handling Fees and Costs"), amounts billed to customers for shipping and handling costs should be classified as revenues, and shipping and handling costs incurred that relate to amounts billed to customers should be classified as expenses in the earnings statement. The company's accounting policy is to classify shipping and handling costs incurred that relate to amounts billed to customers as follows: o As "Operating, selling and general" for downstream refining and marketing operations; and o Deducted from "Sales and other operating revenues" for upstream operations. The company's accounting policy is acceptable under Canadian GAAP, which does not specifically address accounting for shipping and handling costs. The impact of EITF 00 - 10, which is one of reclassification only and does not affect net earnings, is to increase 2001 "Sales and other operating revenues" and "Operating, selling and general" expenses by $95 million (2000 - $96 million; 1999 - $65 million). (2) Under Canadian GAAP, no compensation cost has been recognized in the consolidated statements of earnings for common share options granted to executives, certain employees and non-employee directors under the company's share option programs. Had compensation cost been determined on the basis of fair values in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation", 2001 net earnings would have been lower by $9 million (2000 - $7 million; 1999 - $5 million) and 2001 earnings per share would have been lower by $0.04 (2000 - $0.03; 1999 - $0.02). Under U.S. GAAP (Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"), compensation expense is also recorded, over the same vesting period, for the portion of awards payable in common shares to employees under the company's long-term employee incentive plans. The impact of this GAAP difference is to decrease 2001 net earnings by $14 million (2000 - $22 million; 1999 - nil). Since the common shares awarded under these plans are to be issued from treasury, the income tax impact on the company is nil. (3) Under Canadian GAAP, the preferred securities issued in 1999 are classified as share capital in the consolidated balance sheets and the interest distributions thereon, net of income taxes, are accounted for as dividends in the consolidated statements of changes in shareholders' equity. Under US GAAP, the preferred securities are classified as long-term borrowings in the consolidated balance sheets and the interest distributions thereon and the related income tax impact are accounted for in the consolidated statements of earnings. Under US GAAP, the portion of the preferred securities that is denominated in US dollars, U.S. $163 million, is valued at the exchange rate in effect at the year end. Under Canadian GAAP, issue costs of the preferred securities, net of the related income tax credits, are charged against share capital. Under US GAAP, issue costs are deferred on the consolidated balance sheets and amortized to earnings over the term of the related long-term borrowings. This difference in classification decreased 2001 net earnings by $28 million after income tax recoveries of $23 million (2000 decreased net earnings by $31 million after income tax recoveries of $23 million; 1999 - decreased net earnings by $20 million after income tax recoveries of $17 million). However, the interest distributions on the preferred securities above are eligible for interest capitalization under U.S. GAAP, resulting in an increase in 2001 net earnings of $9 million after future income taxes of $5 million (2000 - increased net earnings by $9 million after future income taxes of $6 million; 1999 - increased net earnings by $2 million after future income taxes of $2 million). The net effect of all of the above differences decreased 2001 net earnings by $27 million (2000 - $22 million; 1999 - $18 million). These preferred securities, which are publicly traded, had a fair value, based on quoted market prices, of $575 million at December 31, 2001 (2000 - $544 million; 1999 - $492 million). Under Canadian GAAP, the 2001 interest distributions of $48 million (2000 - $47 million; 1999 - $37 million) on the preferred securities are classified as financing activities in the consolidated statements of cash flows. Under U.S. GAAP (SFAS No.95, "Statement of Cash Flows"), the interest distributions and the 2001 amortization of issue costs of $3 million (2000 - $7 million) are classified as operating activities. (4) Effective April 5, 2001, the company sold its interest in the Stuart oil shale project and, as a result, the company wrote off the carrying value of the interest. Under Canadian GAAP, the carrying value of the interest in the Stuart oil shale project is calculated as the estimated future cash flow from use together with its residual value, calculated on an undiscounted basis. Under U.S. GAAP (SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"), the carrying value of the interest in the Stuart oil shale project is calculated as the estimated net cash flows, but calculated on a discounted basis. As a result of this GAAP difference in the calculation of the carrying value of the interest in the Stuart oil shale project, the write down in 2000 and the subsequent write off in 2001 of the carrying value of the interest is different under US GAAP. The impact of this GAAP difference is to increase 2001 net earnings by $64 million, after income taxes of $55 million (2000 decrease net earnings by $64 million, after income tax recoveries of $55 million). (5) Under U.S. GAAP (AICPA Statement of Position 98-5, "Reporting the Costs of Start-Up Activities"), all costs relating to start-up activities are expensed as incurred. Under Canadian GAAP, certain costs relating to the company's start-up activities are initially capitalized and then amortized over the estimated useful lives of the related assets. Under Canadian GAAP, in 2001, the remaining costs associated with the Stuart oil shale project that were previously capitalized were written down. Under U.S. GAAP, these start-up costs were expensed in 1999. These differences increased 2001 net earnings by $10 million after related income taxes of $7 million (2000 - increased net earnings by $8 million after related income taxes of $6 million; 1999 - decreased net earnings by $12 million after related income tax credits of $8 million). (6) In December 2000, the Canadian Federal Department of Finance released draft legislation that merged federal budget proposals announced earlier in the year. The draft legislation was enacted into law in June, 2001. Under Canadian GAAP, the budget proposals were considered to be substantially enacted at December 31, 2000. Accordingly, future income tax assets and liabilities at December 31, 2000 were measured taking into account the reduction in tax rates presented in the draft legislation. Under US GAAP, in accordance with SFAS 109 "Accounting for Income Taxes", changes in tax rates and tax laws are considered only after they have been enacted into law. The impact of this GAAP difference was to increase 2001 net earnings by $6 million (2000 - decrease net earnings by $6 million; 1999 - nil). (7) Under U.S. GAAP (SFAS No.87, "Employers' Accounting for Pensions"), recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is greater than accrued pension costs otherwise recorded. No such adjustment is required under Canadian GAAP. Recording the additional minimum liability affects the consolidated balance sheet only and has no impact on net earnings or cash flows. An intangible asset equal to the amount of any unamortized liabilities arising from plan amendments is recognized. Any excess of the additional minimum liability over the amount recognized as an intangible asset is recorded as a separate component of equity (net of any related income tax recoveries), and is included as a component of comprehensive income under SFAS No. 130, "Reporting Comprehensive Income". At December 31, 2001, an additional minimum pension liability of $52 million (2000 - $3 million), an intangible asset of $12 million (2000 - nil) and other comprehensive income of $28 million (2000 - $2 million), net of income tax recoveries of $12 million (2000 - $1 million), was recognized under U.S. GAAP. The impact of this GAAP difference is to decrease 2001 other comprehensive income by $28 million (2000 - decrease of $2 million; 1999 - increase of $6 million). (8) Derivative Financial Instruments Effective January 1, 2001, the company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS 138, (the Standards), which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchase and sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the effective portions of the changes in the fair value of the derivative, and changes in the fair value of the hedged item attributable to the hedged risk, are recognized in the income statement. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income (OCI) and are recognized in the income statement when the hedged item is recognized. Accordingly, ineffective portions of changes in the fair value of hedging instruments are recognized in earnings immediately. Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same earnings statement caption as the hedged item. Gains or losses from derivative instruments for which hedge accounting is not applied are reported in other income. In accordance with the transition provisions of the Standards, the company recorded the following after-tax cumulative adjustments on January 1, 2001: A decrease in OCI of $173 million, net of future income tax recoveries of $87 million and an increase in 2001 US GAAP earnings of $47 million net of future income taxes of $28 million. Assets increased by $89 million and liabilities increased by $274 million as a result of recording all derivative instruments on the consolidated Balance Sheet at fair value. Commodity Price Risk The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of market prices for its petroleum and natural gas products. The company manages its Canadian dollar crude price exposure by entering into US dollar WTI derivative transactions and in some instances combines US dollar WTI derivative transactions and Canadian/US foreign exchange derivative contracts. The company has hedged future cash flows subject to commodity price risk for up to four years. Interest Rate Risk The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest bearing debt. The company has interest rate derivatives outstanding for up to two years classified as cash flow hedges. During 1996, the company entered into a cross currency swap transaction to convert its 7.4% Debentures to a 6.2% fixed interest rate U.S. dollar obligation of approximately $91 million. Later in 1996, the company entered into another cross currency interest rate swap transaction to convert the U.S. $91 million obligation back to a fixed rate Canadian $125 million obligation. The net effect of the two swap transactions was to reduce the effective interest rate on the debentures from 7.3% (7.4% coupon rate) to 5.5%. The transactions did not qualify for hedge accounting. In 2001, the company monetized the two swap transactions and realized a gain of $5.7 million of which, $4.9 million was deferred for Canadian purposes. The entire gain was recognized in current period earnings for US purposes. Inventory Monetization In 1999, the company sold inventory and subsequently entered into a derivative contract with an option to repurchase the inventory at the end of five years. The company realized an economic benefit as a result of liquidating a portion of its inventory. The derivative did not qualify for hedge accounting because the company did not have purchase price risk associated with the repurchase of the inventory. This derivative does not represent a US GAAP difference as the company records this derivative at fair value for Canadian purposes. During the year, the company settled early a long-term contract that was designated as a hedge under Canadian GAAP. Under US GAAP, the long-term contract was designated as a normal purchase and sale. Accordingly, the payment of $29 million was deferred for Canadian purposes and for US purposes, was recognized in current period earnings. For Canadian GAAP, the $29 million will be recognized in income as the hedged item is settled. A reconciliation of changes in OCI attributable to derivatives and hedging activities is as follows:
------------------------------------------------------------------------------------------------------ OCI ---------------------------------------------------------------------- ------------------------------- (millions $) ------------------------------------------------------------------------------------------------------ Net derivative losses, net of $87 million future tax recoveries, arising from implementation of the Standards (173) ------------------------------------------------------------------------------------------------------ Current period net hedging gains arising from cash flow hedges, net of $50 million future tax expense 79 ------------------------------------------------------------------------------------------------------ Net hedging losses at beginning of the period reclassified to earnings during the period, net of $62 million future tax recoveries 123 ------------------------------------------------------------------------------------------------------ Total net hedging gain net of future tax of $13 million 29 ------------------------------------------------------------------------------------------------------
During the year, assets increased by $93 million and liabilities increased by $44 million as a result of recording all derivative instruments on the consolidated Balance Sheet at fair value. The loss associated with hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $25 million net of $12 million tax. The company estimates that $3 million of hedging losses net of future tax recoveries of $2 million will be reclassified from OCI to current period earnings within the next 12 months as a result of forecasted sales occurring. There were no derivative instruments designated as fair value hedges. Implementation of the standards did not affect the company's cash flows or liquidity. The Standards are complex and subject to a potentially wide range of interpretations in their application. The FASB continues to consider several issues, and the potential exists for additional issues to be brought under its review. Therefore, if subsequent FASB interpretations of the Standards are different than the company's initial application, it is possible that the impact of the company's application of the Standards, as described above, will be modified. RECENTLY ISSUED ACCOUNTING STANDARDS ASSET RETIREMENT OBLIGATIONS In August 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued. This statement changes the method and timing of accruing for costs arising from legal obligations associated with the retirement of tangible capital assets and the associated asset retirement costs. The company will evaluate the impact and timing of implementing SFAS 143, which must be adopted no later than January 1, 2003. IMPAIRMENT OF LONG-LIVED ASSETS In August 2001, SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets" was issued. SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains its fundamental provisions for recognition and measurement of impairment of long-lived assets to be held and used, and measurement of long-lived assets to be disposed of by sale. SFAS 144 also supersedes the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" for segments of a business to be disposed of, but retains APB 30's requirement to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. The company will evaluate the impact of implementing SFAS 144, which must be adopted on January 1, 2002. HEDGING RELATIONSHIPS In 2001, the Accounting Standards Board of the CICA approved a new Accounting Guideline, "Hedging Relationships", which deals with the identification, documentation and effectiveness of hedging relationships for the purpose of applying hedge accounting. The Guideline is meant to codify certain best practices and, wherever possible, harmonize with certain requirements of U.S. GAAP, in particular SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 138. The company will evaluate the impact of implementing the new standard, which must be adopted no later than January 1, 2003. FOREIGN CURRENCY TRANSLATION In 2001, the Accounting Standards Board of the Canadian Institute of Chartered Accountants approved amendments to CICA Handbook Section 1650, Foreign Currency Translation. The amendments to Section 1650, applicable for the company in fiscal 2002 with retroactive application, eliminate the deferral and amortization method for unrealized translation gains and losses on non current monetary assets and liabilities and require the disclosure of exchange gains and losses included in net income. STOCK-BASED COMPENSATION In 2001, the Accounting Standards Board of the Canadian Institute of Chartered Accountants approved amendments to CICA Handbook Section 3870, Stock-Based Compensation and Other Stock-Based Payments. Under the amendments to Section 3870, stock-based payments to non-employees and direct awards of stock to employees and non-employees will be accounted for using a fair value method of accounting. The standard provides for the recognition of compensation expense based on fair values or a disclosure only basis of accounting. The standard is effective for years beginning on or after January 1, 2002. The company will apply this standard in fiscal 2002 and has not yet determined the impact. Implementation of the above noted accounting standards will not affect the company's cash flows or liquidity. OIL AND GAS DATA The following data supplements oil and gas disclosure in the company's Annual Report, and is provided in accordance with the provision of the United States Financial Accounting Standards Board's Statement No. 69. This statement requires disclosure about conventional oil and gas activities only, and therefore the company's oil sands activities are excluded. COSTS INCURRED
COSTS INCURRED FOR THE YEARS ENDED DECEMBER 31, ------------ 2001 2000 1999 ---- ---- ---- ($ MILLIONS) Property acquisition costs Proved properties.................................. - 5 - Unproved properties................................ 11 10 48 Exploration costs.................................... 35 40 64 Development costs.................................... 84 69 70 --- --- --- 130 124 182 === === ===
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, ------------ 2001 2000 1999 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers................... 128 139 97 Transfers to other operations..................... 207 183 153 --- --- --- 335 322 250 --- --- --- Expenses Production costs.................................. 36 47 63 Depreciation, depletion and amortization.......... 61 68 76
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, ------------ 2001 2000 1999 ---- ---- ---- ($ MILLIONS) Exploration....................................... 31 63 52 Gain on disposal of assets........................ (8) (147) (36) Restructuring costs............................... (2) 65 - Other related costs............................... 21 25 21 --- --- --- 139 121 176 --- --- --- Operating profit before income taxes................. 196 201 74 Related income taxes................................. (79) (103) (33) ---- --- ---- Results of operations from Natural Gas................ 117 98 41 === === ===
The information noted above does not totally agree to the segmented information on page 51 of the company's annual report due to different classification of revenues and expenses, STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES In computing the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes, assumptions other than those mandated by SFAS No. 69 could produce substantially different results. The Company cautions against viewing this information as a forecast of future economic conditions or revenues, and does not consider it to represent the fair market value of gas properties. Figures are based on year-end commodity prices, and are as follows:
2001 2000 1999 Year end natural gas price assumptions (AECO - $/mcf) 3.55 13.52 2.90
Actual future net cash flows may differ from those estimated due to, but not limited to, the following: o Production rates could differ from those estimated both in terms of timing and amount; o Future prices and economic conditions will likely differ from those at yearend; o Future production and development costs will be determined by future events and may differ from those at year end; and o Estimated income taxes may differ in terms of amounts and timing due to the above factors as well as changes in enacted rates and the impact of future expenditures on unproved properties. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. At December 31, 2001, no such contractual arrangements existed. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, the Company has also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and reclamation and environmental remediation costs. Deducting future income tax expenses then reduces the estimated pretax future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax cash flows relating to the Company's proved oil and gas reserves less the tax basis of the properties involved. At December 31, 2001, there were no legislated future tax rate changes. The future income tax expenses give effect to permanent differences and tax credits and allowances relating to the company's proved oil and gas reserves. The resultant future net cash flows are reduced to present value amounts by applying the SFAS No. 69 mandated 10% discount factor. The result is referred to as "Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes".
2001 2000 1999 ---- ---- ---- ($ MILLIONS) Future cash inflows.......................................... 2,266 8,176 3,272 Future production and development costs...................... (652) (633) (1,053) Other related future costs................................... (283) (175) (133) Future income tax expenses................................... (521) (3,426) (789) ---- ----- ----- Future net cash flows......................................... 810 3,942 1,297 Discount at 10 %.............................................. (370) (2,009) (548) ---- ----- ----- Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes................................... 440 1,933 749 === ===== =====
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES
2001 2000 1999 ---- ---- ---- ($ MILLIONS) Balance, beginning of year.............................................. 1,933 749 797 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas net of related costs............... (297) (275) (192) Revisions to estimates of proved reserves: Prices.............................................................(3,055) 3,886 458 Development costs................................................... (50) (3) (68) Production costs.................................................... (9) 55 (25) Quantities.......................................................... (2) (363) (175) Other............................................................... (16) (237) (81) Extensions, discoveries, and improved recovery less related costs...... 23 177 46 Development costs incurred during the period........................... 81 69 70 Purchases of reserves in place......................................... - 41 - Sales of reserves in place............................................. (1) (989) (130) Accretion of discount.................................................. 361 115 113 Income taxes.......................................................... 1,472 (1,292) (64) ----- ------- ---- Balance, end of year..................................................... 440 1,933 749 === ===== ===
EX-2 4 a2075015zex-2.txt EXHIBIT 2 MANAGEMENT'S STATEMENT ON FINANCIAL REPORTING The financial statements on pages 46 to 68, which consolidate the financial results of Suncor Energy Inc., its subsidiaries and joint ventures, and all information in this annual report, are the responsibility of management. The financial statements have been prepared in accordance with Canadian generally accepted accounting principles. They include some amounts that are based on estimates and judgments relating to matters not concluded by year-end. Financial information presented elsewhere in this annual report is consistent with that in the financial statements. In management's opinion the financial statements have been properly prepared within reasonable limits of materiality and within the framework of the accounting policies summarized on pages 46 to 48. In meeting its responsibilities for the integrity of the financial statements, management maintains a system of internal controls and an internal audit program. Management also administers a program of proper business conduct compliance. PricewaterhouseCoopers LLP, the company's independent auditors, have audited the accompanying financial statements. Their report accompanies this statement. The Audit Committee of the Board of Directors, composed of five independent directors, meets regularly with management, the internal auditors and PricewaterhouseCoopers LLP to review their activities and to discuss auditing, management information systems, internal control, accounting policy and financial reporting matters. The Audit Committee also meets quarterly to review and approve interim financial statements prior to release. The internal auditors and PricewaterhouseCoopers LLP have unrestricted access to the company, the Audit Committee and the Board of Directors. The Audit Committee reviews the financial statements and Management's Discussion and Analysis and recommends approval to the Board of Directors. /s/ Rick George /s/ Mike O'Brien RICK GEORGE MIKE O'BRIEN President and Executive Vice President, Chief Executive Officer Corporate Development and Chief Financial Officer January 16, 2002 AUDITORS' REPORT TO THE SHAREHOLDERS OF SUNCOR ENERGY INC. We have audited the consolidated balance sheets of Suncor Energy Inc. as at December 31, 2001, 2000 and 1999 and the consolidated statements of earnings, cash flows and changes in shareholders' equity for each of the years then ended. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Canada. Those standards require that we plan and perform an audit to obtain reasonable assurance that the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2001, 2000 and 1999 and the results of its operations and cash flows for each of the years then ended in accordance with accounting principles generally accepted in Canada. /s/ PricewaterhouseCoopers PRICEWATERHOUSECOOPERS LLP Chartered Accountants Calgary, Alberta January 16, 2002 2001 ANNUAL REPORT 45 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Suncor Energy Inc. is an integrated Canadian energy company, comprised of three operating segments: Oil Sands, Natural Gas and Sunoco. Oil Sands includes the production of light sweet and light sour crude oil, diesel fuel and various custom blends from oil sands mined in the Athabasca region of northeastern Alberta, and the marketing of these products in Canada and the United States. Natural Gas includes the exploration, acquisition, development, production, transportation and marketing of natural gas and crude oil in Canada and the United States. Sunoco includes the manufacture, transportation and marketing of petroleum and petrochemical products, primarily in Ontario and Quebec, and the marketing of natural gas in Ontario. Petrochemical products are also sold in the United States and Europe. The significant accounting policies of the company are summarized below: (a) PRINCIPLES OF CONSOLIDATION AND THE PREPARATION OF FINANCIAL STATEMENTS These consolidated financial statements are prepared and reported in Canadian dollars in accordance with Canadian generally accepted accounting principles (GAAP), which differ in some respects from GAAP in the United States. The significant differences in GAAP, as applicable to these consolidated financial statements and notes, are described in the company's annual report on Form 40-F, which is filed with the United States Securities and Exchange Commission and is available on request. The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company's proportionate share of the assets, liabilities, revenues, expenses and cash flows of its joint ventures. The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment, regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. (b) CASH EQUIVALENTS AND INVESTMENTS The company considers all highly liquid investments with a maturity of three months or less at the time of purchase to be cash equivalents. Cash equivalents consist primarily of term deposits and certificates of deposit. Investments with maturities from greater than three months to one year are classified as short-term investments, while those with maturities in excess of one year are classified as long-term investments. Cash equivalents and short-term investments are stated at cost, which approximates market value. (c) REVENUES Crude oil sales from upstream operations (Oil Sands and Natural Gas) to downstream operations (Sunoco) are based upon actual product shipments. On consolidation, revenues from these sales are eliminated from sales and other operating revenues and purchases of crude oil and products. The company also uses a portion of its natural gas production for internal consumption at its oil sands plant and refinery. On consolidation, revenues from these sales are eliminated from sales and other operating revenues and operating, selling and general expenses. Revenues associated with sales of crude oil, natural gas, petroleum and petrochemical products and all other items not eliminated on consolidation are recorded when title passes to the customer. Revenues from natural gas production from properties in which the company has an interest with other producers are recognized on the basis of the company's net working interest. (d) PROPERTY, PLANT AND EQUIPMENT COST Property, plant and equipment are recorded at cost. The company follows the successful efforts method of accounting for its crude oil and natural gas operations. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are capitalized initially. If it is determined that the well does not contain proved reserves, the capitalized exploratory drilling costs are charged to expense, as dry hole costs, at that time. The related land costs are expensed through the amortization of unproved properties as covered under the Natural Gas section of the depreciation, depletion and amortization policy below. Development costs, which include the costs of wellhead equipment, development drilling costs, gas plants and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface are expensed as operating costs. INTEREST CAPITALIZATION Interest costs relating to major capital projects and to the portion of non-producing oil and gas properties expected to become producing are capitalized as part of the cost of such property, plant and equipment. Capitalization of interest ceases when the capital asset is substantially complete and ready for its intended productive use. 46 SUNCOR ENERGY INC. LEASES Leases entered into by the company as lessee that transfer substantially all the benefits and risks of ownership to the lessee are recorded as capital leases and classified as property, plant and equipment with offsetting long-term borrowings. All other leases are classified as operating leases under which leasing costs are expenses in the period in which they are incurred. Gains and losses on the sale and leaseback of assets recorded as capital leases are deferred and amortized to earnings in proportion to the amortization of leased assets. DEPRECIATION, DEPLETION AND AMORTIZATION OIL SANDS: Property, plant and equipment are depreciated over their useful lives on a straight line basis, except for original lease acquisition costs and related mine assets, which are depreciated over the life of proved reserves on a unit of production basis. The company is depreciating property, plant and equipment as follows: i) mobile equipment over three to 20 years; ii) mine equipment and acquisition costs of original lease over approximately four million barrels of proved reserves; iii) plant and other property and equipment, including new leases, primarily over four to 40 years. NATURAL GAS: Unproved properties of which acquisition costs are individually significant are evaluated for impairment by management. Impairment of unproved properties of which acquisition costs are not individually significant is provided for through amortization of the portion not expected to become producing, based on historical experience, over the average projected holding period. Acquisition costs of proved properties are depleted using the unit of production method based on proved reserves. Capitalized exploratory drilling costs and development costs are depleted on the basis of proved developed reserves. For purposes of the depletion calculation, production and reserves volumes for oil and natural gas are converted to a common unit of measure on the basis of their approximate relative energy content. Gas plants, support facilities and equipment are depreciated on a straight line basis over their useful lives, which average 12 years. SUNOCO: Depreciation of property, plant and equipment is on a straight line basis over their useful lives. The refinery and additions thereto are depreciated over an average of 30 years, service stations and related equipment over an average of 20 years and other facilities and equipment over three to 25 years. RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS Reclamation and environmental remediation costs for identified sites are estimated and charged against earnings when there exists a regulatory or statutory requirement or contractual agreement, or when management has made a decision to decommission or restore a site, providing that assessments indicate that such costs are probable and reasonably estimable. Estimated reclamation costs in the company's upstream operations are accrued on the unit of production basis. Estimated environmental remediation costs, which are predominantly in the company's downstream operations, are accrued for those sites where assessments indicate that such work is required. Costs are accrued based upon currently known information, estimated timing of remedial actions, and existing regulatory requirements and technology. Changes in these factors may result in material changes to estimated costs, which will be recognized prospectively when known. IMPAIRMENT Property, plant and equipment are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less related provisions for reclamation and environmental remediation costs and future income taxes, may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, then a write-down to the estimated net recoverable amount is made, with a charge to earnings. DISPOSALS Gains or losses on disposals of property, plant and equipment are generally recognized in earnings. For oil and gas property, plant and equipment, gains or losses are recognized in earnings for significant disposals or disposal of an entire property. However, the acquisition cost of an unproved property surrendered or abandoned that is not individually significant or a partial abandonment of a proved property is charged to accumulated depreciation, depletion or amortization, as appropriate. (e) DEFERRED CHARGES Overburden removal costs incurred to expose oil sands for mining, including depreciation on overburden removal equipment where applicable, are deferred. These costs are amortized based on the amount of oil sands mined in the year, the ratio of total overburden to be removed to total reserves of oil sands to be mined and the removal cost, determined on a last-in, first-out (LIFO) basis, per unit of overburden. The cost of major maintenance shutdowns is deferred and amortized on a straight line basis over the period to the next shutdown that varies from three to seven years. Normal maintenance and repair costs are charged to expense as incurred. Goodwill is reviewed on an ongoing basis by management to determine if the unamortized goodwill balance can be recovered through undiscounted projected future operating cash flows. If it cannot be recovered, the goodwill is considered permanently impaired and the net book value of goodwill would be written down. Oil Sands preproduction costs incurred at the inception of operation are amortized on a unit of production basis over the life of proved producing reserves. 2001 ANNUAL REPORT 47 (f) EMPLOYEE FUTURE BENEFITS The company has employee future benefit programs as follows: o Defined benefit pension plans and a defined contribution pension plan providing retirement benefits for its eligible employees, and supplementary defined benefit pension plans providing additional retirement benefits for its executives; o Other post-retirement benefits, including certain health care and life insurance benefits, for its retired employees and eligible surviving dependants; o Post-employment benefits providing certain benefits to former or inactive employees and eligible surviving dependants, after employment but before retirement under specified circumstances. The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management's best estimates of demographic and financial assumptions, and such cost is accrued rateably from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based upon a year-end market rate of interest. Company contributions to the defined contribution plan are expensed as incurred. (g) INVENTORIES Inventories of crude oil and refined products are valued at the lower of cost using the last-in, first-out (LIFO) method and net realizable value. Materials and supplies are valued at the lower of average cost and net realizable value. (h) DERIVATIVE FINANCIAL INSTRUMENTS The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of market prices for its petroleum and natural gas products and to protect its Canadian dollar income and cash flows against adverse foreign currency exchange movements. The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to interest rate fluctuations. The company does not use derivative financial instruments involving multipliers or leverage. These derivative contracts are initiated within the guidelines of the company's risk management policies, which require stringent authorities for approval and commitment of contracts, designation of the contracts by management as hedges of the related transactions, and monitoring of the effectiveness of such contracts in reducing the related risks. Contract maturities are consistent with the settlement dates of the related hedged transactions. Derivative contracts accounted for as hedges are not recognized in the consolidated balance sheets. Gains or losses on these contracts, including realized gains and losses on hedging derivative contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur. (i) FOREIGN CURRENCY TRANSLATION Monetary assets and liabilities in foreign currencies are translated to Canadian dollars at rates of exchange in effect at the end of the period. Other assets and related depreciation, depletion and amortization, other liabilities, revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. The resulting exchange gains and losses are included in earnings, except for unrealized exchange gains and losses arising on translation of long-term liabilities with fixed or ascertainable lives. These gains and losses are deferred and amortized over the remaining terms of the liabilities. The company's former Stuart Oil Shale Project in Australia was integrated with the company's other activities and was translated in the manner described above. (j) STOCK-BASED COMPENSATION PLANS Under the company's share option programs, common share options are granted to executives, certain employees and non-employee directors. The company does not recognize compensation expense on the issuance of common share options under these programs because the exercise price of the share options is equal to the market value of the common shares at the date of grant. The company also has long-term employee incentive plans that provide awards to certain executives based on the market price of the company's common shares and to all other employees based on the market price of the company's common shares and the achievement of certain performance measurement criteria relating to the company's business segments. These awards vest on April 1, 2002, and are payable at that time, generally in equal amounts of cash and common shares of the company. The estimated costs of the cash portion of these awards, based on share price and expected performance achievement, are recorded as compensation expense over the vesting period. Under the company's directors' compensation plan, non-employee directors of the company may elect to receive half or all of their annual remuneration as directors in common share equivalents. The estimated costs of directors' compensation in the form of these common share equivalents, based on share price, are recorded as compensation expense annually. 48 SUNCOR ENERGY INC. CONSOLIDATED STATEMENTS OF EARNINGS for the years ended December 31
($ millions) 2001 2000 1999 REVENUES Sales and other operating revenues (notes 4, 6 and 18) 3 990 3 385 2 383 Interest 5 3 4 - --------------------------------------------------------------------------------------------------------- 3 995 3 388 2 387 - --------------------------------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products (note 18) 1 391 807 519 Operating, selling and general (note 12) 1 010 918 774 Exploration (note 4) 22 53 40 Royalties (note 3) 134 199 99 Taxes other than income taxes (note 4) 367 361 334 Depreciation, depletion and amortization 360 365 318 Gain on disposal of assets (7) (148) (34) Start-up expenses - Project Millennium (note 8) 141 15 -- Write-off of oil shale assets (note 1) 48 125 -- Restructuring (note 2) (2) 65 -- Interest (note 4) 18 8 26 - --------------------------------------------------------------------------------------------------------- 3 482 2 768 2 076 - --------------------------------------------------------------------------------------------------------- EARNINGS BEFORE INCOME TAXES 513 620 311 - --------------------------------------------------------------------------------------------------------- Provision for income taxes (note 5) Current 4 45 29 Future 121 198 96 - --------------------------------------------------------------------------------------------------------- 125 243 125 - --------------------------------------------------------------------------------------------------------- NET EARNINGS 388 377 186 Dividends on preferred securities (note 15) (26) (26) (22) - --------------------------------------------------------------------------------------------------------- Net earnings attributable to common shareholders 362 351 164 - --------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------- PER COMMON SHARE (dollars) (note 16) Net earnings attributable to common shareholders basic 1.63 1.58 0.74 diluted 1.61 1.57 0.73 - --------------------------------------------------------------------------------------------------------- Cash dividends 0.34 0.34 0.34 - --------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------
See accompanying Summary of Significant Accounting Policies and notes. 2001 ANNUAL REPORT 49 CONSOLIDATED BALANCE SHEETS as at December 31
($ millions) 2001 2000 1999 ASSETS CURRENT ASSETS Cash and cash equivalents 1 21 5 Accounts receivable (notes 4 and 6) 306 407 277 Income taxes recoverable 28 -- -- Future income taxes (note 5) 29 45 14 Inventories (note 7) 258 192 161 - --------------------------------------------------------------------------------------------------------------- Total current assets 622 665 457 Property, plant and equipment, net (note 8) 7 141 5 883 4 528 Deferred charges and other (note 9) 199 166 191 Future income taxes (note 5) 132 119 -- - --------------------------------------------------------------------------------------------------------------- Total assets 8 094 6 833 5 176 - --------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Short-term borrowings 31 64 32 Accounts payable and accrued liabilities (notes 12 and 13) 672 709 616 Income taxes payable -- 15 15 Future income taxes (note 5) 28 9 -- Taxes other than income taxes 42 39 46 Current portion of long-term borrowings (note 10) -- 1 1 - --------------------------------------------------------------------------------------------------------------- Total current liabilities 773 837 710 - --------------------------------------------------------------------------------------------------------------- Long-term borrowings (notes 10 and 11) 3 113 2 192 1 306 Accrued liabilities and other (notes 12 and 13) 251 252 236 Future income taxes (note 5) 1 180 1 080 816 Commitments and contingencies (note 14) SHAREHOLDERS' EQUITY Preferred securities (note 15) 514 514 514 Share capital (note 16) 555 537 524 Retained earnings 1 708 1 421 1 070 - --------------------------------------------------------------------------------------------------------------- Total shareholders' equity 2 777 2 472 2 108 - --------------------------------------------------------------------------------------------------------------- Total liabilities and shareholders' equity 8 094 6 833 5 176 - --------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------
See accompanying Summary of Significant Accounting Policies and notes. Approved on behalf of the Board of Directors: /s/ Rick George /s/ Robert Korthals RICK GEORGE ROBERT KORTHALS Director Director 50 SUNCOR ENERGY INC. CONSOLIDATED STATEMENTS OF CASH FLOWS for the years ended December 31
($ millions) 2001 2000 1999 OPERATING ACTIVITIES Cash flow provided from operations (1), (2) 831 958 591 Decrease (increase) in operating working capital Accounts receivable (note 4) 101 (130) (101) Inventories (66) (31) 14 Accounts payable and accrued liabilities (37) 93 322 Taxes payable (17) 18 12 - --------------------------------------------------------------------------------------------------------------- Cash provided from operating activities 812 908 838 - --------------------------------------------------------------------------------------------------------------- CASH USED IN INVESTING ACTIVITIES (2) (1 680) (1 607) (1 290) - --------------------------------------------------------------------------------------------------------------- NET CASH DEFICIENCY BEFORE FINANCING ACTIVITIES (868) (699) (452) - --------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Increase (decrease) in short-term borrowings (33) 32 16 Proceeds from issuance of long-term borrowings (note 10) 500 -- -- Issuance of preferred securities (note 15) -- -- 507 Stuart Oil Shale Project borrowings -- -- 11 Repayment of commercial paper borrowings (note 15) -- -- (507) Net increase in other long-term borrowings 486 792 510 Issuance of common shares under stock option plan (note 16) 15 9 6 Dividends paid on preferred securities (3) (note 15) (48) (47) (37) Dividends paid on common shares (72) (71) (75) - --------------------------------------------------------------------------------------------------------------- Cash provided from financing activities 848 715 431 - --------------------------------------------------------------------------------------------------------------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (20) 16 (21) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 21 5 26 - --------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF YEAR 1 21 5 - --------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------- PER COMMON SHARE (dollars) (note 16) (1) Cash flow provided from operations 3.73 4.32 2.68 (3) Dividends paid on preferred securities (pre-tax) 0.21 0.21 0.17 - --------------------------------------------------------------------------------------------------------------- Cash flow provided from operations after deducting dividends paid on preferred securities 3.52 4.11 2.51 - --------------------------------------------------------------------------------------------------------------- (2) See Schedules of Segmented Data on pages 54 and 55 - ---------------------------------------------------------------------------------------------------------------
See accompanying Summary of Significant Accounting Policies and notes. CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
Preferred Share Retained ($ millions) Securities Capital Earnings AT DECEMBER 31, 1998 -- 518 981 Net earnings -- -- 186 Dividends paid on preferred securities -- -- (22) Dividends paid on common shares -- -- (75) Issuance of preferred securities (note 15) 514 -- -- Issued for cash under stock option plan -- 6 -- - ------------------------------------------------------------------------------------------------------------ AT DECEMBER 31, 1999 514 524 1 070 Net earnings -- -- 377 Dividends paid on preferred securities -- -- (26) Dividends paid on common shares -- -- (71) Issued for cash under stock option plan -- 9 -- Issued under dividend reinvestment plan -- 4 (4) Income taxes - impact of new standard -- -- 75 - ------------------------------------------------------------------------------------------------------------ AT DECEMBER 31, 2000 514 537 1 421 Net earnings -- -- 388 Dividends paid on preferred securities -- -- (26) Dividends paid on common shares -- -- (72) Issued for cash under stock option plan -- 15 -- Issued under dividend reinvestment plan -- 3 (3) - ------------------------------------------------------------------------------------------------------------ AT DECEMBER 31, 2001 514 555 1 708 - ------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------
See accompanying Summary of Significant Accounting Policies and notes. 2001 ANNUAL REPORT 51 SCHEDULES OF SEGMENTED DATA* for the years ended December 31
Oil Sands Natural Gas Sunoco ($ millions) 2001 2000 1999 2001 2000 1999 2001 2000 1999 EARNINGS REVENUES** Sales and other operating revenues 1 227 544 461 178 237 143 2 585 2 604 1 779 Intersegment revenues (note 18) *** 158 792 428 271 191 163 3 -- -- Interest -- -- -- -- -- -- -- -- -- - -------------------------------------------------------------------------------------------------------------------------------- 1 385 1 336 889 449 428 306 2 588 2 604 1 779 - -------------------------------------------------------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products (note 18) 99 3 6 -- -- -- 1 721 1 783 1 090 Operating, selling and general 481 467 369 64 74 88 350 310 270 Exploration -- -- -- 22 53 40 -- -- -- Royalties 30 98 51 104 101 48 -- -- -- Taxes other than income taxes 12 12 9 3 3 5 351 345 320 Depreciation, depletion and amortization 233 232 177 70 78 87 56 54 53 (Gain) loss on disposal of assets 1 -- 2 (8) (147) (36) -- (1) -- Start-up expenses -- Project Millennium 141 15 -- -- -- -- -- -- -- Write-off of oil shale assets -- -- -- -- -- -- -- -- -- Restructuring -- -- -- (2) 65 -- -- -- -- Interest -- -- -- -- -- -- -- -- -- - -------------------------------------------------------------------------------------------------------------------------------- 997 827 614 253 227 232 2 478 2 491 1 733 - -------------------------------------------------------------------------------------------------------------------------------- EARNINGS (LOSS) BEFORE INCOME TAXES 388 509 275 196 201 74 110 113 46 Provision for income taxes (105) (194) (108) (79) (103) (33) (30) (32) (19) - -------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS (LOSS) 283 315 167 117 98 41 80 81 27 - -------------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------------- As at December 31 TOTAL ASSETS 6 409 5 079 3 178 722 762 962 934 911 849 - -------------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------------- CAPITAL EMPLOYED**** 1 398 1 412 1 352 317 412 727 483 386 405 - -------------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------------- RETURN ON AVERAGE CAPITAL EMPLOYED (%)**** 20.1 22.8 12.9 32.1 17.2 5.5 18.4 20.5 6.0 - -------------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------------- RETURN ON AVERAGE CAPITAL EMPLOYED (%)***** 6.4 10.6 9.2 32.1 17.2 5.5 18.4 20.5 6.0 - -------------------------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------------------------
* The company currently has no foreign geographic segments. See note 4 for information on export sales. Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies. ** One customer, in the Oil Sands segment, in 2001 represented 10% or more ($450 million) of the company's 2001 consolidated revenues. (2000 - two customers represented 10% or more ($493 million and $355 million); 1999 - one customer represented 10% or more ($281 million)). *** Intersegment revenues are recorded at prevailing fair market prices and accounted for as if the sales were to third parties. **** Capital Employed - the total of shareholders' equity and debt (short-term borrowings and current and long-term portions of long-term borrowings), less capitalized costs related to major projects in progress. ***** If capital employed were to include capitalized costs related to major projects in progress, the return on average capital employed would be as stated on this line. See accompanying Summary of Significant Accounting Policies and notes. 52 SUNCOR ENERGY INC. SCHEDULES OF SEGMENTED DATA* (CONTINUED) for the years ended December 31
Corporate and Eliminations Total ($ millions) 2001 2000 1999 2001 2000 1999 EARNINGS REVENUES** Sales and other operating revenues -- -- -- 3 990 3 385 2 383 Intersegment revenues (note 18) *** (432) (983) (591) -- -- -- Interest 5 3 4 5 3 4 - ------------------------------------------------------------------------------------------------------------------------------ (427) (980) (587) 3 995 3 388 2 387 - ------------------------------------------------------------------------------------------------------------------------------ EXPENSES Purchases of crude oil and products (note 18) (429) (979) (577) 1 391 807 519 Operating, selling and general 115 67 47 1 010 918 774 Exploration -- -- -- 22 53 40 Royalties -- -- -- 134 199 99 Taxes other than income taxes 1 1 -- 367 361 334 Depreciation, depletion and amortization 1 1 1 360 365 318 (Gain) loss on disposal of assets -- -- -- (7) (148) (34) Start-up expenses -- Project Millennium -- -- -- 141 15 -- Write-off of oil shale assets 48 125 -- 48 125 -- Restructuring -- -- -- (2) 65 -- Interest 18 8 26 18 8 26 - ------------------------------------------------------------------------------------------------------------------------------ (246) (777) (503) 3 482 2 768 2 076 - ------------------------------------------------------------------------------------------------------------------------------ EARNINGS (LOSS) BEFORE INCOME TAXES (181) (203) (84) 513 620 311 Provision for income taxes 89 86 35 (125) (243) (125) - ------------------------------------------------------------------------------------------------------------------------------ NET EARNINGS (LOSS) (92) (117) (49) 388 377 186 - ------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------ As at December 31 TOTAL ASSETS 29 81 187 8 094 6 833 5 176 - ------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------ CAPITAL EMPLOYED**** 32 22 (121) 2 230 2 232 2 363 - ------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------ RETURN ON AVERAGE CAPITAL EMPLOYED (%)**** 17.9 16.6 8.3 - ------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------ RETURN ON AVERAGE CAPITAL EMPLOYED (%)***** 7.5 9.3 6.4 - ------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------
2001 ANNUAL REPORT 53 SCHEDULES OF SEGMENTED DATA* (CONTINUED) for the years ended December 31
Oil Sands Natural Gas Sunoco ($ millions) 2001 2000 1999 2001 2000 1999 2001 2000 1999 CASH FLOW BEFORE FINANCING ACTIVITIES CASH PROVIDED FROM (USED IN) OPERATING ACTIVITIES: Cash flow provided from (used in) operations Net earnings (loss) 283 315 167 117 98 41 80 81 27 Exploration expenses Cash -- -- -- 12 12 12 -- -- -- Dry hole costs -- -- -- 10 41 28 -- -- -- Non-cash items included in earnings Depreciation, depletion and amortization 233 232 177 70 78 87 56 54 53 Future income taxes 89 189 102 76 101 31 18 (16) (33) Current income tax provision allocated to Corporate 16 5 6 3 2 2 12 48 52 (Gain) loss on disposal of assets 1 -- 2 (8) (147) (36) -- (1) -- Write-off of oil shale assets -- -- -- -- -- -- -- -- -- Restructuring -- -- -- (3) 56 -- -- -- -- Other (4) (12) -- 3 (4) 6 2 6 3 Overburden removal outlays (31) (48) (53) -- -- -- -- -- -- Overburden removal outlays -- Project Millennium (88) (27) -- -- -- -- -- -- -- Increase (decrease) in deferred credits and other (13) 1 4 -- 1 1 (3) 2 1 - -------------------------------------------------------------------------------------------------------------------------------- Total cash flow provided from (used in) operations 486 655 405 280 238 172 165 174 103 Decrease (increase) in operating working capital (35) (169) 83 44 27 27 17 40 69 - -------------------------------------------------------------------------------------------------------------------------------- Total cash provided from (used in) operating activities 451 486 488 324 265 199 182 214 172 - -------------------------------------------------------------------------------------------------------------------------------- CASH PROVIDED FROM (USED IN) INVESTING ACTIVITIES: Capital and exploration expenditures (1 479) (1 808) (1 057) (132) (127) (200) (54) (45) (42) Deferred maintenance shutdown expenditures (5) (3) (22) (2) (1) -- (9) (9) -- Deferred outlays and other investments (2) (5) (7) (1) -- -- (9) (7) (2) Proceeds from disposals 10 101 1 22 314 90 1 2 1 - -------------------------------------------------------------------------------------------------------------------------------- Total cash provided from (used in) investing activities (1 476) (1 715) (1 085) (113) 186 (110) (71) (59) (43) - -------------------------------------------------------------------------------------------------------------------------------- NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES (1 025) (1 229) (597) 211 451 89 111 155 129 - -------------------------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------------------------
* The company currently has no foreign geographic segments. See note 4 for information on export sales. Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies. See accompanying Summary of Significant Accounting Policies and notes. 54 SUNCOR ENERGY INC. SCHEDULES OF SEGMENTED DATA* (CONTINUED) for the years ended December 31
Corporate and Eliminations Total ($ millions) 2001 2000 1999 2001 2000 1999 CASH FLOW BEFORE FINANCING ACTIVITIES CASH PROVIDED FROM (USED IN) OPERATING ACTIVITIES: Cash flow provided from (used in) operations Net earnings (loss) (92) (117) (49) 388 377 186 Exploration expenses Cash -- -- -- 12 12 12 Dry hole costs -- -- -- 10 41 28 Non-cash items included in earnings Depreciation, depletion and amortization 1 1 1 360 365 318 Future income taxes (62) (76) (4) 121 198 96 Current income tax provision allocated to Corporate (31) (55) (60) -- -- -- (Gain) loss on disposal of assets -- -- -- (7) (148) (34) Write-off of oil shale assets 48 125 -- 48 125 -- Restructuring -- -- -- (3) 56 -- Other 7 (7) 4 8 (17) 13 Overburden removal outlays -- -- -- (31) (48) (53) Overburden removal outlays -- Project Millennium -- -- -- (88) (27) -- Increase (decrease) in deferred credits and other 29 20 19 13 24 25 - ------------------------------------------------------------------------------------------------------------------------------ Total cash flow provided from (used in) operations (100) (109) (89) 831 958 591 Decrease (increase) in operating working capital (45) 52 68 (19) (50) 247 - ------------------------------------------------------------------------------------------------------------------------------ Total cash provided from (used in) operating activities (145) (57) (21) 812 908 838 - ------------------------------------------------------------------------------------------------------------------------------ CASH PROVIDED FROM (USED IN) INVESTING ACTIVITIES: Capital and exploration expenditures (13) (18) (51) (1 678) (1 998) (1 350) Deferred maintenance shutdown expenditures -- -- -- (16) (13) (22) Deferred outlays and other investments (7) (1) (1) (19) (13) (10) Proceeds from disposals -- -- -- 33 417 92 - ------------------------------------------------------------------------------------------------------------------------------ Total cash provided from (used in) investing activities (20) (19) (52) (1 680) (1 607) (1 290) - ------------------------------------------------------------------------------------------------------------------------------ NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES (165) (76) (73) (868) (699) (452) - ------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------
2001 ANNUAL REPORT 55 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. OIL SHALE PROJECT Effective April 5, 2001, the company sold its interest in the Stuart Oil Shale Project to joint venture co-owners Southern Pacific Petroleum NL and Central Pacific Minerals NL (SPP/CPM). Under the terms of the sale, the company retains a 5% royalty interest in Stage 1 of the project and SPP/CPM and the company retain worldwide rights to the Alberta Taciuk Processor technology. The company made total payments as part of the transaction in the amount of $5 million (AUD$7 million), which SPP/CPM will use to fund Stage 1 operating, capital and transition costs. The company received 2.5 million SPP shares and 0.926 million CPM shares in consideration. SPP/CPM issued the company 12.5 million SPP share options and 4.6 million CPM share options, exercisable over five years at a strike price of AUD$1.25 per SPP share and AUD$3.38 per CPM share. The company surrendered its partly paid Restricted Class shares (SPP 57 million and CPM 18.85 million) that were acquired in 1997. In the second quarter of 2001, as a result of the sale of this interest, the company wrote off the carrying value of the property, plant and equipment and the partly paid shares, and extinguished the long-term borrowings and accrued interest. The earnings impact of the sale of Suncor's remaining interest in the project was $48 million pre-tax, $3 million after-tax. At December 31, 2001, the company holds 2.5 million SPP shares and 0.926 million CPM shares, and 12.5 million SPP share options and 4.6 million CPM share options. The SPP and CPM shares have declined in value and have been written down from $5 million to $2 million. The impact of the write-down was to decrease net earnings by $2 million. 2. RESTRUCTURING CHARGE In 2000, the carrying values of certain assets of the company's Natural Gas business were written down to their net estimated recoverable amount and a provision for estimated restructuring costs was recorded. In the third quarter of 2001, some of these properties that were previously written down were sold and provisions for estimated restructuring costs were revised to reflect increased employee termination costs as follows:
($ millions) 2001 2000 Non-cash charges: Impairment of non-core proved properties -- 21 Impairment of non-core unproved properties (3) 18 Write-down of capitalized development costs on proved properties -- 17 Cash charges: Employee terminations 1 6 Consultants and other -- 3 - --------------------------------------------------------------------------- (2) 65 - --------------------------------------------------------------------------- - ---------------------------------------------------------------------------
The impact of these adjustments is to increase net earnings by $1 million (2000 - decreased net earnings by $30 million). 3. ROYALTIES Oil Sands Crown royalty payments in 2001 were based on a minimum royalty rate of 1% of gross revenues (2000 and 1999 - 5% of gross revenues).
2001 2000 1999 ($ millions) Crown Other Total Crown Other Total Crown Other Total Oil Sands 15 15 30 87 11 98 48 3 51 Natural Gas 93 11 104 90 11 101 40 8 48 Total 108 26 134 177 22 199 88 11 99
56 SUNCOR ENERGY INC. 4. SUPPLEMENTAL INFORMATION
($ millions) 2001 2000 1999 Export sales (1) 590 478 233 - ---------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------- Exploration expenses Geological and geophysical 11 10 10 Other 1 2 2 - ---------------------------------------------------------------------------------- Cash costs 12 12 12 Dry hole costs 10 41 28 - ---------------------------------------------------------------------------------- Cash and dry hole costs (2) 22 53 40 Leasehold impairment (3) 9 10 12 - ---------------------------------------------------------------------------------- 31 63 52 - ---------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------- Taxes other than income taxes Excise taxes (4) 343 336 311 Production, property and other taxes 24 25 23 - ---------------------------------------------------------------------------------- 367 361 334 - ---------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------- Interest expense Long-term interest cost 143 112 71 Less interest capitalized (125) (104) (45) - ---------------------------------------------------------------------------------- 18 8 26 - ---------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------- Cash interest payments 130 104 63 - ---------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------- Allowance for doubtful accounts 3 3 3 - ---------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------
In 2001, the company had in place a securitization program to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable having a maturity of 45 days or less to a third party. As at December 31, 2001, $166 million in accounts receivable had been sold under the program. Under the recourse provisions, the company would provide indemnification against credit losses to a maximum of $54 million. The company believes it has no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in previous securitizations for the year-ended December 31, 2001 were approximately $44 and $1,804 million, respectively. The company recorded a loss of approximately $3 million on the securitization program in 2001. (1) Sales of crude oil, natural gas and refined products to customers in the United States and petrochemicals in Europe. (2) Exploration expenses in the Consolidated Statements of Earnings. (3) Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings. (4) Excise taxes are also included in sales and other operating revenues in the Consolidated Statements of Earnings. 5. INCOME TAXES THE ASSETS AND LIABILITIES SHOWN ON SUNCOR'S BALANCE SHEETS ARE CALCULATED USING ACCOUNTING RULES KNOWN AS GENERALLY ACCEPTED ACCOUNTING PRINCIPLES. SUNCOR'S INCOME TAXES ARE CALCULATED ACCORDING TO GOVERNMENT TAX LAWS AND REGULATIONS, WHICHCOULD RESULT IN DIFFERENT VALUES FOR SOME ASSETS AND LIABILITIES FOR INCOME TAX PURPOSES. THESE DIFFERENCES ARE KNOWN AS TEMPORARY DIFFERENCES, BECAUSE EVENTUALLY THESE DIFFERENCES WILL REVERSE. THE AMOUNTS SHOWN ON THE BALANCE SHEETS AS FUTURE INCOME TAXES REPRESENT INCOME TAXES THAT WILL EVENTUALLY BE PAYABLE OR RECOVERABLE IN FUTURE YEARS WHEN THESE TEMPORARY DIFFERENCES DO REVERSE. SEE BELOW FOR MORE TECHNICAL DETAILS AND NUMBERS. The provision for income taxes reflects an effective tax rate that differs from the statutory tax rate. A reconciliation of the two rates and the dollar effect is as follows:
2001 2000 1999 ($ millions) Amount % Amount % Amount % Federal tax rate 195 38 236 38 118 38 Provincial abatement (51) (10) (62) (10) (31) (10) Federal surtax 6 1 7 1 3 1 Provincial tax rates 69 14 96 16 48 16 - ------------------------------------------------------------------------------------------------------------------------ STATUTORY TAX AND RATE 219 43 277 45 138 45 Add (deduct) the tax effect of: Crown royalties (see note 3) 48 9 83 13 44 13 Resource allowance (77) (15) (101) (17) (56) (17) Large corporations tax 16 3 10 2 10 3 Tax rate changes on future income taxes* (52) (11) (13) (2) -- -- Attributed Canadian royalty income (6) (1) (13) (2) -- -- Assessments and adjustments (11) (2) (3) -- -- -- Other (12) (2) 3 -- (11) (4) - ------------------------------------------------------------------------------------------------------------------------ INCOME TAXES AND EFFECTIVE RATE 125 24 243 39 125 40 - ------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------
* Includes $(43) million, (9)% related to revaluation of future income tax balances (2000 - $(13) million, (2)%; 1999 - nil). 2001 income tax payments totalled $23 million (2000 - $22 million; 1999 - $5 million). 2001 ANNUAL REPORT 57 At December 31, future income taxes are comprised of the following:
2001 2000 ($ millions) Current Non-current Current Non-current Future income tax assets: Employee future benefits 4 30 2 39 Reclamation and environmental remediation costs 8 19 9 23 Royalties -- 44 -- 43 Employee incentive plans -- 29 -- 10 Inventories 11 -- 20 -- Other 6 10 14 4 - -------------------------------------------------------------------------------------------------------------------------------- 29 132 45 119 - -------------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------------- Future income tax liabilities: Depreciation -- 1 105 -- 1 038 Overburden removal costs -- 30 -- 23 Maintenance shutdown costs -- 10 -- 12 Inventories 10 -- -- -- Other 18 35 9 7 - -------------------------------------------------------------------------------------------------------------------------------- 28 1 180 9 1 080 - -------------------------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------------------------
6. RELATED PARTY TRANSACTIONS The following table summarizes the company's related party transactions for the year and balances at the end of the year. These transactions are in the normal course of operations and have been carried out on the same terms as would apply with unrelated parties.
($ millions) 2001 2000 1999 Revenues Sales to Sunoco joint ventures: Refined products 602 600 395 Petrochemicals 131 128 108 - --------------------------------------------------------------------------- At the end of the year, amounts due from related parties are as follows: Sunoco joint ventures 33 58 45 - ---------------------------------------------------------------------------
Sales to and balances with Sunoco joint ventures are exchange amounts established and agreed to by the related parties. The company has exclusive supply agreements with two Sunoco joint ventures for the sale of refined products. The company plans to maintain its relationship with these joint ventures. The company also has a non-exclusive supply agreement with a Sunoco joint venture for the sale of petrochemicals. 7. INVENTORIES
($ millions) 2001 2000 1999 Crude Oil 115 83 47 Refined Products 71 55 67 Materials and Supplies 72 54 47 Total 258 192 161
The replacement cost at December 31, 2001, of all inventories valued at LIFO exceeded their carrying value by $5 million (2000 - $61 million; 1999 - $37 million). In 2000, the company sold inventories produced in prior years whose LIFO costs were lower than current crude oil and operating costs. The impact of this reduction in inventory was to decrease expenses by $8 million and increase net earnings by $5 million. 58 SUNCOR ENERGY INC. 8. PROPERTY, PLANT AND EQUIPMENT
2001 2000 1999 Accum. Accum. Accum. ($ millions) Cost Provision Cost Provision Cost Provision Oil Sands Plant 1 744 557 1 632 476 1 690 470 Mine and mobile equipment 1 008 337 918 313 850 243 Pipeline costs 81 23 81 20 80 17 Capitalized energy services asset lease 101 6 101 2 -- -- Capitalized aircraft lease 8 -- 8 -- -- -- Project Millennium* 3 618 8 2 536 6 905 -- Project Firebag - in progress 275 -- 101 -- -- -- - ---------------------------------------------------------------------------------------------------------------------------- 6 835 931 5 377 817 3 525 730 - ---------------------------------------------------------------------------------------------------------------------------- Natural Gas Proved properties (note 3) 965 423 877 366 1 190 487 Unproved properties (note 3) 114 48 125 56 344 171 Pipeline 20 17 20 17 22 18 Other support facilities and equipment 14 8 13 6 19 12 - ---------------------------------------------------------------------------------------------------------------------------- 1 113 496 1 035 445 1 575 688 - ---------------------------------------------------------------------------------------------------------------------------- Sunoco Refinery 771 391 745 367 740 350 Marketing and transportation 434 209 405 187 380 165 - ---------------------------------------------------------------------------------------------------------------------------- 1 205 600 1 150 554 1 120 515 - ---------------------------------------------------------------------------------------------------------------------------- Corporate Stuart Oil Shale Project (note 2) -- -- 134 -- 237 -- Other 19 4 6 3 7 3 - ---------------------------------------------------------------------------------------------------------------------------- 19 4 140 3 244 3 - ---------------------------------------------------------------------------------------------------------------------------- 9 172 2 031 7 702 1 819 6 464 1 936 - ---------------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------------- Net property, plant and equipment 7 141 5 883 4 528 - ---------------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------------
Interest capitalized during 2001 totalled $125 million (2000 - $104 million; 1999 - $45 million). Capitalized costs related to the in-progress phase of projects are not being depreciated until the facilities are substantially complete and ready for commercial production to commence. Effective January 1, 2002, Project Millennium commenced commercial production, therefore depreciation will begin in January 2002. * Project Millennium costs include capitalized interest of $229 million (2000 - $111 million; 1999 - $21 million). Start-up costs related to Project Millennium have been expensed. 9. DEFERRED CHARGES AND OTHER
($ millions) 2001 2000 1999 Oil sands overburden removal costs (see below) 101 76 85 Deferred maintenance shutdown costs 34 35 45 Investments 7 8 8 Goodwill 14 14 13 Other 43 33 40 - --------------------------------------------------------------------------------------------- 199 166 191 - --------------------------------------------------------------------------------------------- Oil Sands overburden removal costs Balance - beginning of year 76 85 95 Outlays during year 119 75 53 Depreciation on equipment during year 9 8 6 - --------------------------------------------------------------------------------------------- 204 168 154 Amortization during year (103) (92) (69) - --------------------------------------------------------------------------------------------- Balance - end of year 101 76 85 - --------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------
2001 ANNUAL REPORT 59 10. LONG-TERM BORROWINGS
($ millions) 2001 2000 1999 FIXED RATE BORROWINGS Medium-term Notes, maturing in 2011 Interest payable semi-annually* 500 -- -- Medium-term Notes, maturing in 2007 Interest payable semi-annually 400 400 400 7.4% Debentures, Series C, maturing in 2004 Interest payable semi-annually** 125 125 125 Borrowings under or with support of lines of credit converted to fixed rate obligations by interest rate swap transactions, maturing in 2003. Interest payable quarterly at rates averaging 5.6%*** 110 110 110 Stuart Oil Shale Project borrowings (note 1) -- 73 82 Sunoco joint venture borrowings with interest at rates averaging 7.1% at December 31, 2001 (2000 - 7.7%; 1999 - 7.6%) 6 4 5 - ---------------------------------------------------------------------------------------------------------- 1 141 712 722 Capital leases**** 109 109 -- Less current portion of fixed rate long-term borrowings -- 1 1 - ---------------------------------------------------------------------------------------------------------- 1 250 820 721 - ---------------------------------------------------------------------------------------------------------- VARIABLE RATE BORROWINGS***** Borrowings with interest at variable rates averaging 2.7% at December 31, 2001 (2000 - 6.0%; 1999 - 5.2%) under or with support of lines of credit 1 863 1 372 585 - ---------------------------------------------------------------------------------------------------------- TOTAL LONG-TERM BORROWINGS 3 113 2 192 1 306 - ---------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------
* During 2001, the company issued $500 million of Series 2 Medium-term Notes at an interest rate of 6.7%. The net proceeds received were used to repay commercial paper and bank borrowings. ** During 1996, the company entered into a cross-currency interest rate swap transaction to convert its 7.4% debentures to a 6.2% fixed interest rate U.S. dollar obligation of approximately $91 million. Later in 1996, the company entered into another cross-currency interest rate swap transaction to convert the US$91 million obligation back to a fixed rate Cdn$125 million obligation. The net effect of the two swap transactions was to reduce the effective interest rate on the debentures from 7.3% (7.4% coupon rate) to 5.5%. In 2001, the two swap transactions were terminated, resulting in a deferred gain on settlement of $5 million, which is classified as accrued liabilities in the consolidated balance sheets and which is being recognized in earnings as a reduction of interest expense over the period to maturity of the debentures. *** During 1998, the company entered into interest rate swap transactions to convert $50 million and $60 million of variable rate borrowings to fixed interest rate obligations at 5.5% and 5.7%, respectively. **** Obligations under capital leases are as follows:
($ millions) 2001 2000 Energy services assets lease with interest at 6.82% maturing in 2004 101 101 Aircraft lease with interest at prime plus 0.5% maturing in 2008 8 8 - ---------------------------------------------------------------------- 109 109 - ---------------------------------------------------------------------- - ----------------------------------------------------------------------
Future minimum amounts payable under these capital leases are as follows:
($ millions) 2002 8 2003 8 2004 108 2005 1 2006 -- Later years 6 - --------------------------------------------------------------------------- Total minimum lease payments 131 - --------------------------------------------------------------------------- Less amount representing imputed interest (22) - --------------------------------------------------------------------------- Present value of obligation under capital leases 109 - --------------------------------------------------------------------------- - ---------------------------------------------------------------------------
***** During 1999, the company entered into a cross-currency interest rate swap transaction to convert US$183 million of variable rate borrowings with interest based on 90-day LIBOR to Cdn$278 million with interest based on 90-day bankers acceptances. In 2001, swap transactions for US$71 million (Cdn$109 million) of these borrowings were settled. There was no gain or loss on settlement. LONG-TERM BORROWINGS
(per cent) 2001 2000 1999 Variable rate 60 63 45 Fixed rate 40 37 55
60 SUNCOR ENERGY INC. Principal repayments of long-term borrowings other than obligations under capital leases in each of the next five years are as follows:
($ millions) 2002 -- 2003 3 2004 2 099 2005 -- 2006 -- - ---------------------------------------------------------------
11. LINES OF CREDIT At December 31, 2001, the company had available $2,337 million in credit and term loan facilities, of which $1,112 million had been drawn, as follows: o A facility for $600 million that is fully revolving for 364 days, has a term period of three years and expires in 2004. o A facility for $550 million that is fully revolving for 364 days and expires in 2002. o A facility for US$112 million (Cdn$169 million) that is non-revolving, has been fully drawn and expires in 2004. o A facility for $1,003 million that is fully revolving for six years and expires in 2004. o Uncommitted facilities totalling $15 million, which can be terminated at any time at the option of the lenders. The company is also authorized, supported by unutilized credit and term loan facilities, to issue commercial paper to a maximum of $900 million, having a term not to exceed 364 days. At December 31, 2001, the company had $861 million in commercial paper outstanding. These credit facilities are subject to commitment fees, the amounts of which are not significant. 12. ACCRUED LIABILITIES AND OTHER
($ millions) 2001 2000 1999 Reclamation and Environmental Remediation Costs (a) 61 70 86 Pension Costs (see note 13) 110 95 96 Other (b) 80 87 54 Total 251 252 236
(a) RECLAMATION AND ENVIRONMENTAL REMEDIATION COSTS Total accrued reclamation and environmental remediation costs also include $23 million in current liabilities (2000 - $27 million; 1999 - $13 million). Payments during 2001 totalled $28 million (2000 - $15 million; 1999 - $13 million). (b) EMPLOYEE AND DIRECTOR INCENTIVE PLANS Compensation expense recorded under the company's long-term employee incentive plans was $42 million (2000 - $32 million; 1999 - $26 million). Compensation expense is an estimated amount, based on the market price of the company's common shares and expected performance achievement, and is therefore subject to measurement uncertainty and volatility. Vesting of these plans will occur on April 1, 2002. At December 31, 2001, the estimated portion of these awards expected to be paid in cash of $32 million is included in accrued liabilities, with the remaining $72 million included in accrued liabilities and other. Compensation expense in the form of common share equivalents under the directors' compensation plan is not significant. 13. EMPLOYEE FUTURE BENEFITS WHEN EMPLOYEES WORK FOR SUNCOR, THEY ARE ELIGIBLE TO RECEIVE PENSION, HEALTH CARE AND INSURANCE BENEFITS WHEN THEY RETIRE. THIS BENEFIT OBLIGATION OR COMMITMENT THAT SUNCOR HAS TO EMPLOYEES AND RETIREES AT DECEMBER 31, 2001, WAS $554 MILLION. AS REQUIRED BY GOVERNMENT REGULATIONS AND PLAN PERFORMANCE, SUNCOR SETS ASIDE FUNDS, WHICH ARE IN THE CUSTODY OF AN INDEPENDENT TRUSTEE, TO MEET THESE OBLIGATIONS. AT THE END OF DECEMBER, 2001, PLAN ASSETS TO MEET THE BENEFIT OBLIGATION WERE $301 MILLION. THE EXCESS OF THE BENEFIT OBLIGATION OVER PLAN ASSETS OF $253 MILLION REPRESENTS THE NET UNFUNDED OBLIGATION. SEE BELOW FOR MORE TECHNICAL DETAILS AND NUMBERS. DEFINED BENEFIT PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS The company's defined benefit pension plans provide a pension benefit at retirement based upon years of service and final average earnings. The defined benefit pension plans consist of a funded plan that covers most employees, and unfunded supplementary benefit plans that provide supplemental retirement benefits to executives. Under the funded plan, the company makes contributions to an independent trustee to cover pension payment obligations to retired employees. The trustee acts as the depository for contributions, the disbursing agent and custodian of the pension plan's assets. These assets are managed by a pension fund investment committee, on behalf of the beneficiaries, which retains independent managers and advisers. The company's other post-retirement benefits program, which is unfunded, includes certain health care and life insurance benefits provided to retired employees and eligible surviving dependants. Retirees share in the cost of providing these benefits. 2001 ANNUAL REPORT 61 Company contributions to the funded pension plan, the present value of pension and other post-retirement benefit obligations and periodic benefit costs are determined by an independent actuary in accordance with regulatory requirements, based on management's best estimate of actuarial assumptions. ASSUMPTIONS AND ESTIMATES
Other Post- Pension Benefits retirement Benefits (per cent) 2001 2000 1999 2001 2000 1999 Discount Rate 6.50 7.00 7.25 6.50 7.00 7.25 Expected Return on Plan Assets 7.25 7.25 7.25 -- -- -- Rate of Compen- sation Increase 4.25 4.25 4.25 4.25 4.25 4.25
The following table presents information about the funded status of the plans and obligations recognized in the consolidated balance sheets at December 31:
Pension Benefits Other Post-retirement Benefits 2001 2000 1999 2001 2000 1999 CHANGE IN BENEFIT OBLIGATION Benefit obligation at beginning of year 404 364 403 79 69 72 Service costs 14 12 15 3 3 4 Interest costs 28 26 24 6 5 4 Plan participants' contribution 3 3 2 -- -- -- Amendments -- -- -- -- -- (8) Actuarial (gain) loss 34 23 (61) 7 4 (1) Benefits paid (22) (24) (19) (2) (2) (2) - --------------------------------------------------------------------------------------------------------------------- Benefit obligation at end of year 461 404 364 93 79 69 - --------------------------------------------------------------------------------------------------------------------- CHANGE IN PLAN ASSETS* Fair value of plan assets at beginning of year 322 316 278 -- -- -- Actual return on plan assets (14) 15 39 -- -- -- Employer contribution 12 12 16 -- -- -- Plan participants' contribution 3 3 2 -- -- -- Benefits paid (22) (24) (19) -- -- -- - --------------------------------------------------------------------------------------------------------------------- Fair value of plan assets at end of year 301 322 316 -- -- -- - --------------------------------------------------------------------------------------------------------------------- Net unfunded obligation (160) (82) (48) (93) (79) (69) Items not yet recognized in earnings: Unamortized transitional asset -- (8) (16) -- -- -- Unamortized net actuarial loss 109 45 18 19 13 11 - --------------------------------------------------------------------------------------------------------------------- Accrued benefit liability (51) (45) (46) (74) (66) (58) - --------------------------------------------------------------------------------------------------------------------- Current portion (15) (15) (8) (2) (2) (2) Long-term portion (36) (30) (38) (72) (64) (56) - --------------------------------------------------------------------------------------------------------------------- (51) (45) (46) (74) (66) (58) - --------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------
* Assets in the employees' pension plan consist of marketable equity securities, government and corporate bonds and short-term notes. Pension plan assets are not the company's assets and therefore are not included in the consolidated balance sheets. The above benefit obligation at year-end includes funded and unfunded plans, as follows:
Pension Benefits Other Post-retirement Benefits 2001 2000 1999 2001 2000 1999 Funded plan 377 334 309 -- -- -- Unfunded plans 84 70 55 93 79 69 - --------------------------------------------------------------------------------------------------------------------- Benefit obligation at end of year 461 404 364 93 79 69 - --------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------
62 SUNCOR ENERGY INC. The components of net periodic benefit cost are as follows:
Pension Benefits Other Post-retirement Benefits 2001 2000 1999 2001 2000 1999 Service costs 14 12 15 3 3 4 Interest costs 28 26 24 6 5 4 Expected return on plan assets (23) (22) (22) -- -- -- Amortization of transitional asset (8) (8) (8) -- -- -- Amortization of net actuarial loss 9 6 12 1 1 1 - --------------------------------------------------------------------------------------------------------------------- Net periodic benefit cost 20 14 21 10 9 9 - --------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------
The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 13 years for pension benefits (2000 and 1999 - 13 years), and over the expected average future service life to full eligibility age of 11 years for post-retirement benefits. In order to measure the expected cost of other post-retirement benefits, a 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate was assumed to decrease gradually each year to a rate of 5% for 2010 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for other post-retirement benefit obligations. A 1% change in assumed health care cost trend rates would have the following effects:
1% 1% ($ millions) Increase Decrease Effect on total of service and interest cost components of net periodic post-retirement health care benefit cost 2 (1) - ----------------------------------------------------------------------- Effect on the health care component of the accumulated post-retirement benefit obligation 17 (13) - -----------------------------------------------------------------------
DEFINED CONTRIBUTION PENSION PLAN The company has a defined contribution plan, under which both the company and employees make contributions. Company contributions, which totalled $4 million (2000 - $4 million; 1999 - $4 million), are based on employees' earnings and contributions. 14. COMMITMENTS AND CONTINGENCIES (a) OPERATING COMMITMENTS In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company enters into non-cancellable operating leases for service stations, office space and other property and equipment, as well as transportation service agreements for pipeline capacity and an energy services agreement. Under contracts existing at December 31, 2001, future minimum amounts payable under these leases and agreements are as follows:
Pipeline Capacity Operating ($ millions) and Energy Services * Leases 2002 131 45 2003 134 42 2004 133 36 2005 141 32 2006 148 29 Later years 3 826 89 - ------------------------------------------------------------------ 4 513 273 - ------------------------------------------------------------------ - ------------------------------------------------------------------
* Includes annual tolls payable under a transportation service agreement with a major pipeline company to use a portion of its pipeline capacity and tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreement commenced in 1999 and extends to 2028. As the initial shipper on the pipeline, Suncor's annual tolls payable under the agreement could be subject to annual adjustments. To meet the energy needs of its oil sands operation, Suncor has a commitment under long-term energy agreements to obtain a portion of the power and all of the steam generated by a cogeneration facility owned by a major energy company. Effective October 1999, this company also commenced managing the operations of Suncor's existing energy services facility. (b) CONTINGENCIES The company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated reclamation and environmental remediation costs. These costs are accrued at the company's natural gas and oil sands operations on the unit of production basis. Estimated environmental remediation costs at service stations are also accrued upon completion of site investigations. These costs are reduced by any estimated gains likely to be realized on a sale of these sites. Any changes in these estimates will affect future earnings. 2001 ANNUAL REPORT 63 Under the company's business interruption insurance coverage, the company would bear the first $415 million of any loss arising from a future insured incident at its Oil Sands operations. The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded mainly from the company's cash provided from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any one quarter or year. The company believes that any liabilities which might arise pertaining to such matters would not be expected to have a material effect on the company's consolidated financial position. 15. PREFERRED SECURITIES During 1999, the company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of US$162.5 million of 9.125% preferred securities, the proceeds of which totalled Cdn$507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debentures, due in 2048 and redeemable at the company's option on or after March 15, 2004. Subject to certain conditions, the company has the right to defer payment of interest on the securities for up to 20 consecutive quarterly periods. Deferred interest and principal amounts are payable in cash, or, at the option of the company, from the proceeds on the sale of equity securities of the company delivered to the trustee of the preferred securities. Accordingly, the preferred securities are classified as share capital in the consolidated balance sheet and the interest distributions thereon, net of income taxes, are classified as dividends. Proceeds from the offerings were used to repay commercial paper borrowings. 16. SHARE CAPITAL (a) AUTHORIZED: COMMON SHARES The company is authorized to issue an unlimited number of common shares without nominal or par value. PREFERRED SHARES The company is authorized to issue an unlimited number of preferred shares without nominal or par value in series. (b) ISSUED: The number of common shares and common share options outstanding, common share prices and per share calculations, for both current and prior periods, reflect a two-for-one split of the company's common shares during 2000.
Common Shares ($ millions) Number Amount Balance as at December 31, 1998 220 433 656 518 Issued for cash under stock option plan 587 850 6 Issued under dividend reinvestment plan 10 732 -- - ----------------------------------------------------------------------- Balance as at December 31, 1999 221 032 238 524 Issued for cash under stock option plan 738 176 9 Issued under dividend reinvestment plan 130 165 4 - ----------------------------------------------------------------------- Balance as at December 31, 2000 221 900 579 537 Issued for cash under stock option plan 1 048 069 15 Issued under dividend reinvestment plan 29 597 3 - ----------------------------------------------------------------------- BALANCE AS AT DECEMBER 31, 2001 222 978 245 555 - -----------------------------------------------------------------------
COMMON SHARE OPTIONS i) EXECUTIVE STOCK PLAN Under this plan, the company has granted common share options to non-employee directors and certain executives of the company and its subsidiaries. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted to non-employee directors are exercisable immediately. Options granted to employees are exercisable as follows: one-third after one year, the second third after two years and the final third after three years from the grant date. No option may be exercisable more than 10 years after the grant date. ii) EMPLOYEE STOCK OPTION PROGRAM Under this program, the company granted 1,063,000 share options to certain senior employees. The exercise price for these grants was equal to or greater than the market value of the common shares at the grant date. Options vest and are exercisable on April 1, 2002, one-half at that time and the other half based on achievement of certain performance measurement criteria. 64 SUNCOR ENERGY INC. The following tables cover all common share options granted by the company:
Weighted Exercise price per share (dollars) Number Range Average Outstanding, December 31, 1998 5 397 238 4.75 - 26.38 16.64 Granted 1 090 456 20.25 - 30.18 20.70 Exercised (583 040) 4.75 - 24.55 9.76 Cancelled (46 668) 15.54 - 26.08 25.73 - ------------------------------------------------------------------------------------------------- Outstanding, December 31, 1999 5 857 986 4.75 - 30.18 18.01 Granted 950 016 26.08 - 38.55 31.29 Exercised (737 202) 4.75 - 24.55 12.57 Cancelled (209 925) 20.25 - 33.03 26.03 - ------------------------------------------------------------------------------------------------- Outstanding, December 31, 2000 5 860 875 4.75 - 38.55 20.55 Granted 1 090 360 31.88 - 42.70 35.26 Exercised (1 014 334) 4.75 - 32.95 14.60 Cancelled (52 866) 20.25 - 40.40 28.42 - ------------------------------------------------------------------------------------------------- OUTSTANDING, DECEMBER 31, 2001 5 884 035 4.75 - 42.70 24.24 - ------------------------------------------------------------------------------------------------- Exercisable, December 31 1999 2 609 816 4.75 - 26.98 12.89 - ------------------------------------------------------------------------------------------------- 2000 3 067 594 4.75 - 31.98 15.42 - ------------------------------------------------------------------------------------------------- 2001 3 067 806 4.75 - 42.70 19.34 - -------------------------------------------------------------------------------------------------
Common shares authorized for issuance by the Board of Directors, that remain available for the granting of future options, at December 31:
(number of common shares) 2001 2000 1999 5 298 883 6 336 377 7 076 468
The following table is an analysis of outstanding and exercisable common share options as at December 31, 2001:
Outstanding Exercisable ---------------------------------------------------------- --------------------------------- Weighted Weighted Weighted Average Remaining Average Exercise Average Exercise Exercise Price Number Contractual Life Price Per Share Number Price Per Share 4.75 - 12.80 795 460 3 9.94 795 460 9.94 15.54 - 20.25 1 475 746 6 18.18 1 187 641 17.67 24.55 - 28.12 1 670 761 6 25.56 648 584 24.73 28.40 - 33.73 862 436 8 31.44 335 906 31.49 34.90 - 42.70 1 079 632 9 35.26 100 215 38.03 - ------------------------------------------------------------------------------------------------------------------------- Total 5 884 035 6 24.24 3 067 806 19.34 - ------------------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------------------
2001 ANNUAL REPORT 65 iii) EARNINGS PER COMMON SHARE The following table provides a reconciliation between basic and diluted earnings per share:
($ millions) 2001 2000 1999 Net earnings attributable to common shareholders 362 351 163 Dividends on preferred securities -- ** 26 *** -- **** - ------------------------------------------------------------------------------------------------------------- Net earnings before deducting dividends on preferred securities 362 ** 377 *** 163 **** - ------------------------------------------------------------------------------------------------------------- (millions of common shares) Weighted-average number of common shares 222 221 221 Dilutive securities: Options/shares issued under long-term incentive plan 3 2 2 Preferred securities converted -- ** 17 *** -- **** - ------------------------------------------------------------------------------------------------------------- Weighted-average number of diluted common shares 225 240 223 - ------------------------------------------------------------------------------------------------------------- (dollars per common share) Basic earnings per share 1.63 * 1.58 * 0.74 * Diluted earnings per share 1.61 ** 1.57 *** 0.73 **** - -------------------------------------------------------------------------------------------------------------
* Basic earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of common shares. ** For the year-ended December 31, 2001, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted- average number of diluted common shares. Dividends on preferred securities of $26 million and preferred securities converted of 13 million shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share. *** For the year-ended December 31, 2000, diluted earnings per share is the net earnings before deducting dividends on preferred securities divided by the weighted-average number of diluted common shares. **** For the year-ended December 31, 1999, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted- average number of diluted common shares. Dividends on preferred securities of $22 million and preferred securities converted of 22 million shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share. iv) FAIR VALUE OF OPTIONS GRANTED The weighted average fair value of common share options granted in 2001 is $6.41 per share (2000 - $7.12 per share; 1999- $7.01 per share). The fair value of common share options granted is estimated as at the grant date using the Black-Scholes option-pricing model, using the following assumptions:
2001 2000 1999 Dividend $0.34/ $0.34/ $0.34/ share share share Risk-free interest rate 5.07% 6.45% 4.89% Expected life 5 years 7 years 7 years Expected volatility 35% 37% 32% - ----------------------------------------------------------------------------------------
The company does not recognize compensation cost in the consolidated statement of earnings when common share options are granted to non-employee directors and employees. Had compensation cost been determined on the basis of fair values using the Black-Scholes option-pricing model, 2001 net earnings would have been lower by $9 million (2000 - $7 million; 1999 - $5 million), and 2001 earnings per share would have been lower by $0.04 (2000 - $0.03; 1999 - $0.02). 17. FINANCIAL INSTRUMENTS (a) BALANCE SHEET FINANCIAL INSTRUMENTS The company's financial instruments recognized in the consolidated balance sheets consist of cash and cash equivalents, accounts receivable, derivative contracts not accounted for as hedges, investments in SPP and CPM, substantially all current liabilities, except for income taxes payable and future income taxes, and long-term borrowings. The estimated fair values of recognized financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The fair values of cash and cash equivalents, accounts receivable and current liabilities approximate their carrying amounts due to the short-term maturity of these instruments. At December 31, 2001, the company had outstanding crude oil and U.S. dollar swap contracts maturing in 2004, fixing the purchase price of 2 130 000 barrels of crude oil at Cdn$49 million. These derivative contracts, which have not been accounted for as hedges, had a fair value and carrying value of $13 million at December 31, 2001 (2000 - $10 million; 1999 - $(2) million). The fair value of the company's investment in the shares of SPP and CPM is determined based on quoted market prices. 66 SUNCOR ENERGY INC. The following table summarizes estimated fair value information about the company's long-term borrowings at December 31:
2001 2000 1999 ($ millions) Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Long-term borrowings -- fixed rate 1 025 1 047 525 528 525 516 -- variable rate 1 974 1 974 1 482 1 482 695 695 -- Sunoco joint ventures 6 6 3 3 4 4 -- Stuart Oil Shale Project -- -- 73 73 82 82 -- capital leases 109 109 109 109 -- -- - ------------------------------------------------------------------------------------------------------------------------------
The fair value of the company's fixed rate long-term borrowings, which are publicly traded, is based on quoted market prices. The fair value of the company's variable rate long-term borrowings, capital leases, and proportionate share of the long-term borrowings of its Sunoco joint ventures approximatesthe carrying amount. (b) UNRECOGNIZED DERIVATIVE FINANCIAL INSTRUMENTS The company is also a party to certain derivative financial instruments which are not recognized in the consolidated balance sheets, as follows: REVENUE AND MARGIN HEDGES The company enters into crude oil and foreign currency swap and option contracts to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable U.S./Canadian dollar exchange rate. These contracts reduce fluctuations in sales revenues by locking in fixed prices, or a range of fixed prices, and exchange rates on the portion of its crude oil sales covered by the contracts. The company also enters into crude oil and heating oil swap contracts to lock in fixed margins on the portion of refined product sales covered by the contracts. While these contracts reduce the risk of exposure to adverse changes in commodity prices and exchange rates, they also reduce the potential benefit of favourable changes in commodity prices and exchange rates. The contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company's sales revenues or crude oil purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions. Contracts outstanding at December 31 were as follows:
($ millions except for average price) Quantity Average Price* Revenue Hedged Hedge Period REVENUE HEDGES AS AT DECEMBER 31, 2001 Crude oil swaps and options* 40 576 bbl/day 30 444 2002 424 bbl/day 21 (a) 3 (a) 2002 43 000 bbl/day 22 - 27 (a) 345 - 424 (a) 2002 44 000 bbl/day 21 - 26 (a) 337 - 418 (a) 2003 11 000 bbl/day 21 - 24 (a) 84 - 96 (a) 2004 15 000 bbl/day 22 (a) 120 (a) 2005 - --------------------------------------------------------------------------------------------------------------------------------- AS AT DECEMBER 31, 2000 Crude oil swaps and options* 42 710 bbl/day 28 436 2001 4 790 bbl/day 20 (a) 35 (a) 2001 10 000 bbl/day 26 - 32 (a) 95 - 117 (a) 2001 41 000 bbl/day 28 426 2002 7 000 bbl/day 22 - 26 (a) 56 - 66 (a) 2002 - --------------------------------------------------------------------------------------------------------------------------------- AS AT DECEMBER 31, 1999 Crude oil swaps* 52 655 bbl/day 26 503 2000 9 845 bbl/day 19 (a) 67 (a) 2000 35 000 bbl/day 26 327 2001 4 000 bbl/day 26 38 2002 U.S. dollar swaps US$81 1.41 114 2001 US$289 1.41 408 2002 - --------------------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------------------
* Average price for crude oil swaps is WTI per barrel at Cushing, Oklahoma. (a) Average price and revenue hedged is in U.S. dollars, with no foreign exchange component. 2001 ANNUAL REPORT 67
($ millions except for average margin) Quantity Average Margin Margin Hedged Hedge Period bbl/day US$/bbl US$ MARGIN HEDGES Refined product sales and crude purchase swaps As at December 31, 2001 -- -- -- -- As at December 31, 2000 6 575 5 12 2001 As at December 31, 1999 -- -- -- -- - ---------------------------------------------------------------------------------------------------------------------
INTEREST RATE HEDGES The company enters into interest rate and cross-currency interest rate swap contracts as part of its risk management strategy to minimize exposure to interest rate fluctuations. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and a financial institution. The cross-currency swap contracts involve an exchange of Canadian dollar interest payments and U.S. dollar interest payments between the company and a financial institution, and an exchange of Canadian and U.S. dollar principal amounts at the maturity date of the underlying borrowing to which the swaps relate. The swap transactions are completely independent from and have no direct effect on the relationship between the company and its lenders. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense. The notional amounts of interest rate and cross-currency interest rate swap contracts outstanding at December 31, 2001 are detailed in note 10, Long-Term Borrowings. FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS The fair value of these hedging derivative financial instruments is the estimated amount, based on brokers' quotes, that the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:
($ million) 2001 2000 1999 Revenue hedge swaps and options 54 (247) (136) Margin hedge swaps (2) (11) -- U.S. dollar swaps -- -- (1) Interest rate and cross- currency interest rate swaps 4 5 -- - ---------------------------------------------------------------------------- 56 (253) (137) - ---------------------------------------------------------------------------- - ----------------------------------------------------------------------------
COUNTERPARTY CREDIT RISK The company may be exposed to certain losses in the event that counterparties to the derivative financial instruments are unable to meet the terms of the contracts. The company's exposure is generally limited to those counterparties holding derivative contracts with positive fair values at the reporting date. The company minimizes this risk by entering into agreements only with highly rated financial institutions, and through regular management review of potential exposure to, and credit ratings of, such financial institutions. At December 31, the company had exposure to credit risk with counterparties as follows:
($ millions) 2001 2000 Derivative contracts not accounted for as hedges 12 8 Unrecognized derivative contracts 93 -- - ---------------------------------------------------------------------- 105 8 - ---------------------------------------------------------------------- - ----------------------------------------------------------------------
18. ACCOUNTING FOR INTERSEGMENT REVENUES During the first quarter of 2001, the company changed the methodology of accounting for sales from its upstream operations to its downstream operations from a deeming concept to one based on actual product shipments. Under the deeming concept, upstream sales, except for sales to third parties under long-term contracts, were deemed to be sold to downstream operations and, therefore, eliminated on consolidation whether or not product was actually shipped. The company's current operational activities are such that product shipped from its upstream operations to its downstream operations is considerably less than previous years and therefore, this change better reflects the company's current operational activities and enhances comparability within the industry. The impact of this change in methodology in accounting for intersegment sales, which has been applied prospectively, is to increase both sales and other operating revenues and purchases of crude oil and products by $473 million. There is no impact on consolidated and segmented net earnings. 68 SUNCOR ENERGY INC. QUARTERLY SUMMARY (unaudited)
FINANCIAL DATA Total Total Total For the Quarter Ended Year For the Quarter Ended Year For the Quarter Ended Year Mar June Sept Dec Mar June Sept Dec Mar June Sept Dec ($ millions except 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2001 2001 2001 2001 2001 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 REVENUES 1 001 1 098 1 013 883 3 995 779 820 862 927 3 388 469 564 639 715 2 387 - ----------------------------------------------------------------------------------------------------------------------------- NET EARNINGS (LOSS) Oil Sands 69 108 69 37 283 90 81 76 68 315 17 34 43 73 167 Natural Gas 53 39 13 12 117 8 16 43 31 98 3 13 20 5 41 Sunoco 23 45 12 -- 80 19 20 19 23 81 5 3 12 7 27 Corporate and eliminations (20) (28) (21) (23) (92) (12) (6) (88) (11) (117) (14) (17) (5) (13) (49) - ----------------------------------------------------------------------------------------------------------------------------- 125 164 73 26 388 105 111 50 111 377 11 33 70 72 186 - ----------------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------------- PER COMMON SHARE -- net earnings attributable to common shareholders -- basic 0.53 0.71 0.30 0.09 1.63 0.45 0.47 0.19 0.47 1.58 0.04 0.12 0.29 0.29 0.74 -- diluted 0.52 0.70 0.30 0.09 1.61 0.44 0.46 0.20 0.47 1.57 0.04 0.12 0.29 0.28 0.73 - ----------------------------------------------------------------------------------------------------------------------------- -- cash dividends 0.085 0.085 0.085 0.085 0.34 0.085 0.085 0.085 0.085 0.34 0.085 0.085 0.085 0.085 0.34 - ----------------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------------- CASH FLOW PROVIDED FROM (USED IN) OPERATIONS Oil Sands 140 117 139 90 486 199 181 156 119 655 53 90 104 158 405 Natural Gas 127 76 42 35 280 48 42 64 84 238 42 43 39 48 172 Sunoco 50 67 30 18 165 46 38 49 41 174 23 17 37 26 103 Corporate and eliminations (42) (14) (34) (10) (100) (24) (17) (40) (28) (109) (25) (21) (33) (10) (89) - ----------------------------------------------------------------------------------------------------------------------------- 275 246 177 133 831 269 244 229 216 958 93 129 147 222 591 - ----------------------------------------------------------------------------------------------------------------------------- - -----------------------------------------------------------------------------------------------------------------------------
OPERATING DATA Total Total Total For the Quarter Ended Year For the Quarter Ended Year For the Quarter Ended Year Mar June Sept Dec Mar June Sept Dec Mar June Sept Dec ($ millions except 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2001 2001 2001 2001 2001 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 OIL SANDS PRODUCTION (a) 113.4 109.7 116.5 153.0 123.2 114.8 116.7 114.2 110.0 113.9 95.5 112.0 101.5 113.2 105.6 SALES (a) -- light sweet crude oil 53.0 55.0 54.2 62.4 56.2 67.7 64.3 61.4 64.0 64.3 54.6 41.3 52.1 62.8 52.7 -- diesel 13.5 15.2 15.0 15.3 14.8 8.7 8.6 8.9 11.0 9.3 7.9 6.8 8.4 9.5 8.2 -- light sour crude oil 31.4 31.5 40.6 64.3 42.0 39.1 41.7 35.6 27.5 35.8 27.3 47.9 40.6 35.1 37.5 -- bitumen 8.6 13.0 8.0 4.3 8.5 2.4 3.5 7.0 11.0 6.2 1.5 6.9 6.9 -- 3.8 - ----------------------------------------------------------------------------------------------------------------------------- 106.5 114.7 117.8 146.3 121.5 117.9 118.1 112.9 113.5 115.6 91.3 102.9 108.0 107.4 102.2 - ----------------------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------------------- AVERAGE SALES PRICE (b) -- light sweet crude oil 36.09 36.05 35.20 30.22 34.17 34.35 33.54 36.21 37.22 35.31 20.55 24.47 27.23 30.81 26.06 -- other (diesel, light sour crude oil and bitumen) 25.66 27.12 28.21 20.12 24.86 28.46 28.22 27.84 23.71 27.09 19.18 19.60 21.45 25.91 21.48 -- total 30.84 31.40 31.43 24.43 29.17 31.84 31.12 32.39 31.33 31.67 20.00 21.57 24.24 28.77 23.84 -- total* 38.17 38.35 37.37 25.65 34.21 39.19 39.40 43.41 43.27 41.29 18.52 22.29 27.56 33.72 25.89 Cash operating costs (1) (c) 15.40 17.00 18.25 17.45 17.00 11.10 12.20 14.50 16.40 13.55 12.55 10.90 12.35 11.15 11.70 Total operating costs (2) (c) 18.60 19.65 20.95 19.40 19.60 15.50 16.60 18.55 19.50 17.25 15.60 14.30 15.30 15.10 15.05 - ----------------------------------------------------------------------------------------------------------------------------- - -----------------------------------------------------------------------------------------------------------------------------
2001 ANNUAL REPORT 69
OPERATING DATA (continued) Total Total Total For the Quarter Ended Year For the Quarter Ended Year For the Quarter Ended Year Mar June Sept Dec Mar June Sept Dec Mar June Sept Dec ($ millions except 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2001 2001 2001 2001 2001 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 NATURAL GAS GROSS PRODUCTION** Conventional -- natural gas (d) 177 177 176 180 177 222 195 200 183 200 229 225 231 219 226 -- natural gas liquids (a) 2.3 2.3 2.4 2.4 2.4 3.5 3.1 2.8 2.5 3.0 4.7 4.1 4.1 4.0 4.2 -- crude oil (a)*** 1.7 1.5 1.5 1.3 1.5 8.1 3.5 3.6 1.6 4.2 10.8 9.7 8.4 7.9 9.2 -- total (e) 33.5 33.3 33.2 33.7 33.4 48.6 39.1 39.7 34.6 40.5 53.7 51.3 51.0 48.4 51.1 AVERAGE SALES PRICE -- natural gas (f) 10.73 6.78 3.90 3.10 6.09 2.96 3.70 4.63 8.02 4.72 2.18 2.15 2.48 2.96 2.44 -- natural gas (f)* 10.81 6.82 3.90 3.09 6.12 2.97 3.70 4.62 8.05 4.73 2.10 2.17 2.58 3.11 2.48 -- natural gas liquids (b) 45.07 39.62 30.26 23.47 34.38 33.16 32.80 39.56 43.00 36.66 11.88 16.70 22.81 27.12 19.32 -- crude oil -- conventional (b) 37.35 36.75 33.17 27.17 33.92 26.30 30.04 33.09 36.01 29.50 18.48 20.48 20.55 25.21 20.94 -- crude oil -- conventional (b)* 42.12 42.30 37.86 28.60 38.14 38.23 38.65 42.31 44.35 39.80 16.28 21.89 28.01 32.72 24.01 SUNOCO Refined product sales (g)**** 14.9 15.3 15.1 14.0 14.8 14.3 15.1 14.0 15.2 14.6 13.1 14.1 13.9 14.2 13.8 Natural gas sales (d) 92 102 95 92 95 84 78 74 95 83 93 86 87 90 89 Margins -- refining (3) (h) 6.2 8.1 4.3 3.7 5.7 5.4 6.3 6.1 5.8 5.9 3.4 3.3 4.8 4.3 4.0 -- retail (4) (h) 6.1 7.6 5.9 6.9 6.6 6.8 6.4 6.4 7.0 6.6 7.9 7.6 6.9 7.2 7.4 Utilization of refining capacity (%) 88 98 99 83 92 102 99 96 95 98 97 93 100 92 95 - -----------------------------------------------------------------------------------------------------------------------------
* Excludes the impact of hedging activities. ** Currently all Natural Gas production is located in the Western Canada Sedimentary Basin. *** Before deducting 2001 Alberta Crown royalty of 0.2 thousand barrels per day (2000 - 0.5 thousand barrels per day; 1999 - 0.9 thousand barrels per day). **** Excludes sales through joint venture interests. Definitions (1) Cash operating costs - operating, selling and general expenses, taxes other than income taxes, and overburden cash expenditures for the period. (2) Total operating costs - cash and non-cash operating costs (total Oil Sands expenses less purchases of crude oil and products and royalties in Schedules of Segmented Data on page 52 and 53). (3) Refining margin - average wholesale unit price from all products minus average unit cost of crude oil. (4) Retail margin - average street price of Sunoco-branded retail gasoline minus refining gasoline price. (a) thousands of barrels per day (b) dollars per barrel (c) dollars per barrel sold rounded to the nearest $0.05 (d) millions of cubic feet per day (e) BOE (6:1 basis) per day (f) dollars per thousand cubic feet (g) thousands of cubic metres per day (h) cents per litre Metric conversion Crude oil, refined products, etc. 1m3 (cubic metre) = approx. 6.29 barrels Natural gas 1m3 (cubic metre) = approx. 35.49 cubic feet 70 SUNCOR ENERGY INC. FIVE-YEAR FINANCIAL SUMMARY (unaudited)
($ millions except for ratios) 2001 2000 1999 1998 1997 REVENUES Oil Sands 1 385 1 336 889 768 751 Natural Gas 449 428 306 290 302 Sunoco 2 588 2 604 1 779 1 533 1 673 Corporate and eliminations (427) (980) (587) (521) (572) - ------------------------------------------------------------------------------------------------------------------- 3 995 3 388 2 387 2 070 2 154 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- NET EARNINGS (LOSS) Oil Sands 283 315 167 145 175 Natural Gas 117 98 41 24 23 Sunoco 80 81 27 37 36 Corporate and eliminations (92) (117) (49) (28) (20) - ------------------------------------------------------------------------------------------------------------------- 388 377 186 178 214 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- CASH FLOW PROVIDED FROM (USED IN) OPERATIONS Oil Sands 486 655 405 320 331 Natural Gas 280 238 172 167 162 Sunoco 165 174 103 112 121 Corporate and eliminations (100) (109) (89) (19) (39) - ------------------------------------------------------------------------------------------------------------------- 831 958 591 580 575 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- CAPITAL AND EXPLORATION EXPENDITURES Oil Sands 1 479 1 808 1 057 507 491 Natural Gas 132 127 200 242 240 Sunoco 54 45 42 60 54 Corporate 13 18 51 127 62 - ------------------------------------------------------------------------------------------------------------------- 1 678 1 998 1 350 936 847 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- TOTAL ASSETS 8 094 6 833 5 176 4 104 3 457 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- CAPITAL EMPLOYED* Debt Short-term borrowings 31 64 32 16 36 Current portion of long-term borrowings -- 1 1 1 6 Long-term borrowings 3 113 2 192 1 306 1 298 767 Shareholders' equity 2 777 2 472 2 108 1 499 1 391 - ------------------------------------------------------------------------------------------------------------------- 5 921 4 729 3 447 2 814 2 200 Less capitalized costs related to major projects in progress (3 691) (2 497) (1 084) (373) (599) - ------------------------------------------------------------------------------------------------------------------- 2 230 2 232 2 363 2 441 1 601 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- RATIOS Per common share (dollars) -- net earnings attributable to common shareholders 1.63 1.58 0.74 0.81 0.98 -- cash dividends 0.34 0.34 0.34 0.34 0.34 -- cash flow provided from operations 3.73 4.32 2.68 2.64 2.62 -- cash flow provided from operations attributable to common shareholders 3.52 4.11 2.51 2.64 2.62 Return on capital employed (%)* 17.9 16.6 8.3 9.5 14.3 Return on shareholders' equity (%)* 14.8 16.5 10.3 12.3 16.2 Debt to debt plus shareholders' equity (%) 53.1 47.7 38.9 46.7 36.8 Debt to cash flow provided from operations (times) 3.8 2.3 2.3 2.2 1.4 Interest coverage - cash flow basis* 5.9 9.0 9.1 8.7 15.4 Interest coverage - net earnings basis* 3.7 5.6 5.1 4.8 9.2 - -------------------------------------------------------------------------------------------------------------------
* Definitions Capital employed - see page 52. Return on shareholders' equity - earnings as a percentage of average shareholders' equity. Average shareholders' equity is the aggregate of total shareholders' equity at the beginning and end of the year divided by two. Interest coverage - cash flow basis - cash provided from operations before interest expense and current income tax provision, divided by interest expense plus interest capitalized. Interest coverage - net earnings basis - net earnings before interest expense and income tax payments, divided by interest expense plus interest capitalized. 2001 ANNUAL REPORT 71 SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)
2001 2000 1999 1998 1997 OIL SANDS PRODUCTION (thousands of barrels per day) 123.2 113.9 105.6 93.6 79.4 SALES (thousands of barrels per day) Light sweet crude oil 56.2 64.3 52.7 58.8 53.5 Diesel 14.8 9.3 8.2 9.7 10.0 Light sour crude oil 42.0 35.8 37.5 26.6 14.6 Bitumen 8.5 6.2 3.8 -- -- - -------------------------------------------------------------------------------------------------------------------- 121.5 115.6 102.2 95.1 78.1 - -------------------------------------------------------------------------------------------------------------------- AVERAGE SALES PRICE (dollars per barrel) Light sweet crude oil 34.17 35.31 26.06 22.80 26.65 Other (diesel, light sour crude oil and bitumen) 24.86 27.09 21.48 21.16 25.74 Total 29.17 31.67 23.84 22.18 26.36 Total* 34.21 41.29 25.89 20.37 27.98 Cash operating costs (dollars per barrel rounded to the nearest $0.05)** 17.00 13.55 11.70 11.75 13.25 Total operating costs (dollars per barrel rounded to the nearest $0.05)** 19.60 17.25 15.05 14.00 15.80 OTHER OIL SANDS STATISTICS Overburden removed (millions of cubic metres) 50.9 30.7 22.5 22.2 17.5 Oil sands mined (millions of tonnes) 97.9 84.9 72.9 62.4 54.1 Average bitumen content of oil sands mined (per cent by weight) 10.4 11.1 11.6 11.6 12.7 Average crude yield of oil sands mined (barrels per tonne) .459 .491 .529 .547 .535 - --------------------------------------------------------------------------------------------------------------------
* Excludes the impact of hedging activities. **See definitions on page 70. SYNTHETIC CRUDE OIL AND BITUMEN GROSS RESERVES*
Firebag Mining Reserves In-situ Total Synthetic Crude Oil Bitumen Proved and (millions of barrels) Proved Probable Total Probable Probable December 31, 1997 338 463 801 -- 801 - ------------------------------------------------------------------------------------------- December 31, 1998 302 464 766 -- 766 Revisions (10) (13) (23) -- (23) Additions 222 1 577 1 799 -- 1 799 Production (38) -- (38) -- (38) - ------------------------------------------------------------------------------------------- December 31, 1999 476 2 028 2 504 -- 2 504 Revisions (13) 6 (7) -- (7) Production (41) -- (41) -- (41) - ------------------------------------------------------------------------------------------- December 31, 2000 422 2 034 2 456 -- 2 456 Revisions (1) (5) (6) -- (6) Additions -- -- -- 2 029 2 029 Production (45) -- (45) -- (45) - ------------------------------------------------------------------------------------------- DECEMBER 31, 2001 376 2 029 2 405 2 029 4 434 - -------------------------------------------------------------------------------------------
Gross proved reserves do not reflect deductions in respect of Crown and applicable sublease royalties. Under the Crown Royalty Agreement, the Crown royalty rate is dependent on deemed net revenues; therefore, calculations of the net reserves would vary depending upon assumed production rates, prices and operating and capital costs. * Reserve estimates are based upon a detailed geological assessment, including drilling and laboratory analysis. Estimates also reflect the integrated nature of the operation and therefore reflect demonstrated productive capacity, upgrading yield, plans for increased output, operating life and regulatory constraints. 72 SUNCOR ENERGY INC. SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (CONTINUED) (unaudited)
2001 2000 1999 1998 1997 NATURAL GAS PRODUCTION Conventional Natural gas (millions of cubic feet per day) - gross 177 200 226 247 240 - net 124 142 170 195 199 Natural gas liquids (thousands of barrels per day) - gross 2.4 3.0 4.2 4.9 5.0 - net 1.7 2.1 3.0 3.7 3.5 Crude oil (thousands of barrels per day) - gross 1.5 4.2 9.2 11.4 10.7 - net 1.1 3.3 7.5 9.4 8.6 Total (thousands of boe* per day) - gross 33.4 40.5 51.1 57.5 55.7 - net 23.5 29.1 38.8 45.6 45.3 AVERAGE SALES PRICE Natural gas (dollars per thousand cubic feet) 6.09 4.72 2.44 1.95 1.93 Natural gas (dollars per thousand cubic feet)** 6.12 4.73 2.48 1.95 1.94 Natural gas liquids (dollars per barrel) 34.38 36.66 19.32 15.13 22.45 Crude oil - conventional (dollars per barrel) 33.92 29.50 20.94 20.14 22.75 - conventional (dollars per barrel)** 38.14 39.80 24.01 17.37 24.80 UNDEVELOPED LANDHOLDINGS*** Oil and gas (millions of acres) - western provinces - gross 0.6 1.4 1.5 1.7 1.7 - net 0.5 1.1 1.2 1.3 1.3 - international - gross 1.7 1.3 -- -- -- - net 1.3 1.1 -- -- -- NET WELLS DRILLED**** Conventional Exploratory - oil -- -- 1 2 7 - gas 4 1 5 10 10 - dry 16 15 13 18 25 Development - oil -- 2 2 15 26 - gas 16 14 4 16 10 - dry 2 3 1 8 4 - ---------------------------------------------------------------------------------------------------------- 38 35 26 69 82 - ---------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------
* Barrel of oil equivalent (boe) converts gas to oil on the approximate long-term economic equivalent basis that 6,000 cubic feet equals one barrel of oil. ** Excludes the impact of hedging activities. *** Metric conversion: Landholdings - 1 hectare = approximately 2.5 acres. **** Excludes interests in 14 net exploratory wells and seven net development wells in progress at the end of 2001. OIL AND GAS DATA The following supplemental oil and gas disclosure is provided in accordance with the provisions of the United States Statement of Financial Accounting Standards (SFAS) No. 69. This statement requires disclosure about conventional oil and gas activities only, and therefore the company's oil sands activities are excluded. Additional information required by SFAS No. 69 is included in the company's Form 40-F report, which is filed in the Electronic Data Gathering, Analysis and Retrieval (EDGAR) system of the United States Securities and Exchange Commission (SEC). This information can be accessed on the internet at www.freeedgar.com. 2001 ANNUAL REPORT 73 SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (CONTINUED) (unaudited)
RESERVES Gross Net Crude Oil and Natural Crude Oil and Natural Natural Gas Liquids Gas Natural Gas Liquids Gas (millions of (billions of (millions of (billions of barrels) cubic feet) barrels) cubic feet) PROVED December 31, 1997 70 1 088 56 850 - ----------------------------------------------------------------------------------------------------------------------------- December 31, 1998 69 1 197 56 915 Revisions of previous estimates (2) (103) (2) (80) Purchases of minerals in place -- 1 -- 1 Extensions and discoveries -- 53 -- 41 Production (5) (82) (4) (68) Sales of minerals in place (11) (53) (9) (45) - ----------------------------------------------------------------------------------------------------------------------------- December 31, 1999 51 1 013 41 764 Revisions of previous estimates (3) (52) (6) (81) Purchases of minerals in place -- 9 -- 7 Extensions and discoveries 1 39 1 28 Production (3) (73) (2) (52) Sales of minerals in place (30) (139) (23) (99) - ----------------------------------------------------------------------------------------------------------------------------- December 31, 2000 16 797 11 567 Revisions of previous estimates (1) (3) -- 4 Extensions and discoveries -- 27 -- 20 Production (1) (65) (1) (45) Sales of minerals in place -- (1) -- (1) - ----------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2001 14 755 10 545 - ----------------------------------------------------------------------------------------------------------------------------- PROVED DEVELOPED December 31, 1997 55 727 44 568 December 31, 1998 53 730 43 557 December 31, 1999 38 627 30 471 December 31, 2000 13 573 10 414 DECEMBER 31, 2001 11 573 8 416 - -----------------------------------------------------------------------------------------------------------------------------
Proved reserves are considered recoverable under current technology and existing economic conditions, from reservoirs that are evaluated on known drilling, geological, geophysical and engineering data. Proved developed reserves are on production, or reserves that could be recovered from existing wells or facilities, if the company placed them on production. Gross reserves are before deducting royalties. Net reserves are after deducting royalties. Royalties can vary depending upon factors such as prices, production volumes, timing of initial production and changes in legislation. All reserves are located in Canada. There has been no major discovery or other favourable or adverse event which caused a significant change in estimated proved reserves since December 31, 2001. The company has no long-term supply agreements or contracts with governments or authorities in which it acts as producer nor does it have any interest in oil and gas operations accounted for by the equity method.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES ($ millions) 2001 2000 1999 At December 31 440 1 933 749
74 SUNCOR ENERGY INC. SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (CONTINUED) (unaudited)
2001 2000 1999 1998 1997 SUNOCO REFINED PRODUCT SALES (thousands of cubic metres per day) Transportation fuels Gasoline - retail* 4.3 4.2 4.1 4.1 3.8 - other 4.4 4.0 3.7 3.5 3.3 Jet fuel 0.7 1.1 1.1 1.0 1.2 Diesel 3.1 3.1 2.7 2.5 2.6 - --------------------------------------------------------------------------------------------------------------------- 12.5 12.4 11.6 11.1 10.9 Petrochemicals 0.5 0.6 0.7 0.7 0.7 Heating oils 0.4 0.4 0.4 0.6 1.0 Heavy fuel oils 0.8 0.6 0.5 0.7 0.7 Other 0.6 0.6 0.6 0.7 0.9 - --------------------------------------------------------------------------------------------------------------------- 14.8 14.6 13.8 13.8 14.2 - --------------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------------- NATURAL GAS SALES (millions of cubic feet per day) 95 83 89 88 14 MARGINS (cents per litre) Refining 5.7 5.9 4.0 4.1 4.6 Retail 6.6 6.6 7.4 7.0 6.8 CRUDE OIL SUPPLY AND REFINING Processed at Suncor Energy refinery (thousands of cubic metres per day) 10.2 10.9 10.6 11.0 10.8 Utilization of refining capacity (%) 92 98 95 99 97 RETAIL OUTLETS** (number at year-end) 400 402 415 423 441 * Excludes sales through joint venture interests. **Sunoco-branded service stations, other private brands managed by Sunoco and Sunoco's interest in service stations managed through joint ventures. Outlets are located mainly in Ontario. - --------------------------------------------------------------------------------------------------------------------- TOTAL SUNCOR EMPLOYEES (number at year-end) 3 307 3 043 2 796 2 659 2 439 - --------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------
2001 ANNUAL REPORT 75 SHARE TRADING INFORMATION (unaudited) (Stock trading symbol SU) The following share trading information reflects a two-for-one split of the company's common shares during 2000.
For the Quarter Ended For the Quarter Ended Mar 31 June 30 Sept 30 Dec 31 Mar 31 June 30 Sept 30 Dec 31 2001 2001 2001 2001 2000 2000 2000 2000 SHARE OWNERSHIP Average number outstanding, weighted monthly (thousands) (1) 222 115 222 463 222 631 222 910 221 064 221 265 221 562 221 773 SHARE PRICE (dollars) (2) Toronto Stock Exchange High 44.40 44.25 48.20 53.70 34.95 36.90 39.80 38.80 Low 31.70 37.05 38.05 41.50 27.25 31.20 30.50 29.40 Close 40.55 38.60 44.00 52.40 31.45 34.20 33.20 38.30 New York Stock Exchange - US$ High 28.60 30.00 30.25 33.60 22.00 24.95 26.75 26.40 Low 21.00 24.35 25.00 26.10 18.50 20.80 20.50 19.40 Close 25.90 25.70 27.90 32.90 21.25 23.25 22.15 25.70 SHARES TRADED (thousands) Toronto Stock Exchange 45 160 50 115 38 514 50 206 42 976 32 903 37 181 43 177 New York Stock Exchange 3 539 6 379 6 669 6 943 3 014 3 268 2 371 2 851 PER COMMON SHARE INFORMATION (dollars) Net earnings attributable to common shareholders 0.53 0.71 0.30 0.09 0.45 0.47 0.19 0.47 Cash dividends 0.085 0.085 0.085 0.085 0.085 0.085 0.085 0.085 - ----------------------------------------------------------------------------------------------------------------------------
(1) The company had approximately 1,225 holders of record of common shares as at January 31, 2002. (2) The company's common shares are traded on the Toronto and New York stock exchanges. INFORMATION FOR SECURITY HOLDERS OUTSIDE CANADA Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to Canadian non-resident withholding tax of 15%. The withholding tax rate is reduced to 5% on dividends paid to a corporation if it is a resident of the United States that owns at least 10% of the voting shares of the company. 76 SUNCOR ENERGY INC. INVESTOR INFORMATION STOCK TRADING SYMBOLS AND EXCHANGE LISTING Common shares (SU) are listed on the Toronto and New York stock exchanges. Suncor's 9.05% preferred securities (SU.PR.A-T) are listed on the Toronto Stock Exchange. Suncor's 9.125% preferred securities (SU.PR.A-N) are listed on the New York Stock Exchange. DIVIDENDS Suncor's Board of Directors reviews its dividend policy from time to time. In 2001, an aggregate dividend of $0.34 per share was paid. DIVIDEND REINVESTMENT AND COMMON SHARE PURCHASE PLAN Suncor's Dividend Reinvestment and Common Share Purchase plan provides an efficient and cost-effective way for shareholders to increase their investment in the company. The plan enables resident Canadian and U.S. shareholders to invest cash dividends in common shares or acquire additional shares through optional cash payments without payment of brokerage commissions, service charges or other costs associated with administration of the plan. To obtain additional information, please call Computershare Trust Company of Canada at 1-888-267-6555. STOCK TRANSFER AGENT AND REGISTRAR In Canada, Suncor's agent is Computershare Trust Company of Canada with locations in Calgary, Edmonton, Toronto, Montreal and Vancouver. In the United States, Computershare Trust Company, Inc. is located in Denver, Colorado. ACCOUNT MANAGEMENT Sometimes shareholders receive more than one copy of Suncor's Annual Report because their shares are registered under different names or addresses. If you receive but do not require more than one mailing, call Computershare Trust Company of Canada at 1-888-267-6555 to make arrangements to combine your accounts. ANNUAL MEETING Suncor's annual and special meeting of shareholders will be held at 10 a.m. MST on April 26, 2002, at the Keyano College Theatre in Fort McMurray, Alberta. Presentations from the meeting will be web cast at www.suncor.com. CORPORATE OFFICE Box 38, 112 - 4th Avenue SW Calgary, Alberta, T2P 2V5 tel: (403) 269-8100 toll free: 1-866-SUNCOR-1 fax: (403) 269-6217 info@suncor.com ANALYST AND INVESTOR INQUIRIES John Rogers Vice President, Investor Relations tel: (403) 269-8670 fax: (403) 269-6217 info@suncor.com ADDITIONAL INFORMATION In addition to annual and quarterly reports, Suncor publishes a bi-annual Report on Sustainability. To order copies of Suncor's print materials call 1-800-558-9071. More information about Suncor and print materials that can be downloaded are available from www.suncor.com. LA VERSION FRANCAISE DU RAPPORT ANNUEL DE SUNCOR ET DE SON RAPPORT DE DURABILITE PEUT ETRE TELECHARGEE A L'ADRESSE SUIVANTE : www.suncor.com 2001 ANNUAL REPORT 77 CORPORATE DIRECTORS AND OFFICERS OFFICERS J. KENNETH ALLEY Vice President, Finance M. (MIKE) ASHAR Executive Vice President, Oil Sands DAVID W. BYLER Executive Vice President, Natural Gas and Renewable Energy RICHARD L. GEORGE President and Chief Executive Officer TERRENCE J. HOPWOOD Senior Vice President and General Counsel SUE LEE Senior Vice President, Human Resources and Communications KEVIN D. NABHOLZ Senior Vice President, Major Projects MICHAEL W. O'BRIEN Executive Vice President, Corporate Development and Chief Financial Officer JANICE B. ODEGAARD Vice President, Associate General Counsel and Corporate Secretary THOMAS L. RYLEY Executive Vice President, Energy Marketing and Refining JR SHAW Chairman of the Board DIRECTORS MEL E. BENSON 1, 4 Calgary, Alberta Management Consultant Director since 2000 BRIAN A. CANFIELD 3, 4 Point Roberts, Washington Chairman, TELUS Corporation Director since 1995 Chair, Human Resources and Compensation Committee BRYAN P. DAVIES 1, 4 Toronto, Ontario Senior Vice President, Regulatory Affairs Royal Bank of Canada Director since 2000 JOHN T. FERGUSON 1, 2 Edmonton, Alberta Chairman, Princeton Development Ltd. Chairman, TransAlta Corporation Director since 1995 RICHARD L. GEORGE 2 Calgary, Alberta President and Chief Executive Officer Suncor Energy Inc. Director since 1991 POUL HANSEN 1, 4, 5 Vancouver, British Columbia Chairman and General Manager Sperling Hansen Associates Inc. Director since 1996 JOHN R. HUFF 2, 3 Houston, Texas Chairman and Chief Executive Officer Oceaneering International, Inc. Director since 1998 ROBERT W. KORTHALS 1, 2 Toronto, Ontario Director since 1996 Chair, Audit Committee M. ANN McCAIG 3, 4 Calgary, Alberta President, VPI Investments Ltd. Director since 1995 Chair, Environment, Health and Safety Committee JR SHAW 2, 3 Calgary, Alberta Executive Chair, Shaw Communications Inc. Chairman of the Board, Suncor Energy Inc. Director since 1998 Chair, Board Policy, Strategy Review and Governance Committee W. ROBERT WYMAN 2, 3, 5 Vancouver, British Columbia Director since 1987 1 Audit Committee 2 Board Policy, Strategy Review and Governance Committee 3 Human Resources and Compensation Committee 4 Environment, Health and Safety Committee 5 Retiring in April 2002 78 SUNCOR ENERGY INC. EX-3 5 a2075015zex-3.txt EXHIBIT 3 M A N A G E M E N T 'S D I S C U S S I O N A N D A N A L Y S I S This Management's Discussion and Analysis contains forward-looking statements based on current expectations, but which involve certain risks, uncertainties and assumptions. Actual results may differ materially. See page 44 for additional information. All financial information is reported in Canadian dollars unless noted otherwise. In 2001, Suncor began to convert natural gas to crude oil equivalent at a ratio of six thousand cubic feet to one barrel. Figures for past years have been restated to reflect this change. S U N C O R O V E R V I E W A N D S T R A T E G I C P R I O R I T I E S Suncor Energy Inc. is an integrated Canadian energy company with its corporate office located in Calgary, Alberta. Suncor's cornerstone business, Oil Sands, mines and upgrades oil sands near Fort McMurray, Alberta, to produce custom-blended refinery feedstocks and diesel fuel. Suncor's conventional Natural Gas production in Western Canada is sold in North American markets, creating an internal hedge against the company's natural gas consumption. The company refines crude oil and markets finished petroleum products through its subsidiary, Sunoco Inc., headquartered in Toronto, Ontario. Suncor's strategy is based on: o Expanding Oil Sands facilities to increase oil production and provide greater operational flexibility. o Developing Suncor's large resource base through oil sands mining and in-situ technology. o Controlling costs through a strong operational focus, economies of scale and improved management of engineering, procurement and construction on major projects. o Supporting integration and growth through natural gas production that offsets internal demand and by expanding the downstream marketing of Oil Sands products. o Actively managing environmental and social issues associated with operations to help build support for Suncor's growth plans among community, government and other stakeholders. [GRAPHIC DESCRIPTION] NET EARNINGS (per cent) 2001 2000 1999 Oil Sands 59 64 71 Natural Gas 24 20 17 Sunoco 17 16 12 [GRAPHIC DESCRIPTION] CASH FLOW PROVIDED FROM OPERATIONS (per cent) 2001 2000 1999 Oil Sands 52 62 60 Natural Gas 30 22 25 Sunoco 18 16 15 [GRAPHIC DESCRIPTION] CAPITAL EMPLOYED (per cent) 2001 2000 1999 Oil Sands 64 64 55 Natural Gas 14 19 29 Sunoco 22 17 16 NET EARNINGS COMPONENTS
($ millions after income taxes) 2001 2000* 1999 Operational earnings** 433 414 167 NATURAL GAS Asset divestments 4 69 19 Restructuring 1 (30) -- STUART OIL SHALE PROJECT Partial asset write-down (3) (80) -- OIL SANDS Start-up expenses - Project Millennium (90) (9) -- Impact of provincial income tax rate reductions on opening future income tax balances*** 43 13 -- - ----------------------------------------------------------------------------------- Net earnings 388 377 186 ===================================================================================
CASH FLOW FROM OPERATIONS COMPONENTS
($ millions) 2001 2000 1999 Operational cash flow** 1 061 1,009 591 NATURAL GAS Restructuring costs (1) (9) -- OIL SANDS Start-up expenses & overburden removal - Project Millennium (229) (42) -- - ----------------------------------------------------------------------------------- Cash flow provided from operations 831 958 591 ===================================================================================
INCOME TAX RATE CHANGES IMPACT OF PROVINCIAL INCOME TAX RATE REDUCTIONS ON OPENING FUTURE INCOME TAX BALANCES*
TOTAL ($ millions) Oil Sands Natural Gas Sunoco Corporate 2001 2000 31 9 10 (7) 43 13 ===================================================================================
* The determination of operational earnings for 2000 has been restated to be consistent with the treatment and presentation in 2001 of the impact of income tax rate reductions. ** Suncor's presentation of operational earnings and operational cash flow are provided to enhance readers' understanding of the factors impacting Suncor's operational and financial performance and should not be used to compare Suncor's financial results with those of other companies. For comparability purposes readers should rely on the reported net earnings and cash flow provided from operations and the related per share information, which are prepared and presented in accordance with Canadian generally accepted accounting principles in the Consolidated Financial Statements. *** See Note 5 to the Consolidated Financial Statements. For information related to quarterly sales, net income and net income per share for the years 2001 and 2000 refer to the information under the heading Quarterly Summary on pages 69 and 70 of this 2001 Annual Report, which information is incorporated by reference into this Management's Discussion and Analysis. EARNINGS ANALYSIS NET EARNINGS UP 3% IN 2001 Net earnings for the year increased to $388 million, up from $377 million in 2000. Cash flow provided from operations was $831 million, compared with $958 million in 2000. During 2001 and 2000, several transactions impacted net earnings and cash flow provided from operations that were not viewed as ongoing. These transactions in 2001 included start-up expenses of Suncor's major oil sands expansion, Project Millennium, restructuring cost adjustments and a divestment gain in Natural Gas, adjustments related to the revaluation of opening future provincial income tax balances due to a reduction in income tax rates and Suncor's sale of the Stuart Oil Shale Project. Non-operational transactions are explained in the Notes to the Consolidated Financial Statements. Operational earnings in 2001 increased to $433 million from $414 million in 2000. The $19 million increase was primarily the result of increased Oil Sands sales, lower crude oil hedging losses, higher natural gas prices, the benefit of a royalty rate reduction for Oil Sands production and higher downstream retail gasoline margins and volumes. These factors were partially offset by lower crude oil prices, the widening of light/heavy crude oil differentials, the impact of two maintenance shutdowns that halted Oil Sands production for a total of 16 days and higher operating expenses and interest charges. 2001 ANNUAL REPORT 23 Operational cash flow in 2001 increased over 2000 primarily due to the same factors that increased earnings. Operational cash flow also increased as a result of the favourable income tax impact from the sale of the company's interest in the Stuart Oil Shale Project. These favourable factors were partially reduced by recognition at December 31, 2001 of the $32 million estimated payment to be made in 2002 under Suncor's long-term employee compensation programs. Subsequent to year-end it was determined that 2001 performance targets were achieved and the final payout will be based upon the average weekly closing common share price in the first quarter of 2002. Based on current share prices it is estimated the total cash cost of these programs will be approximately $108 million. The payment with respect to these programs in the second quarter of 2002 will be $72 million. This payment is approximately $30 million higher as a result of elections subsequent to the year-end with respect to the form of payment under one component of these programs. This $30 million change will decrease cash flow provided from operations in the first quarter of 2002. Up to the end of 2001 the after-tax cumulative cost since the programs' inception in 1997 that had been charged against Suncor's earnings was $67 million. CONSOLIDATED EARNINGS ANALYSIS Sales and other operating revenues were $3,990 million in 2001, up from $3,385 million in 2000. The increase was primarily the result of the items discussed below: o During the first quarter of 2001, Suncor changed the methodology of accounting for sales from its upstream to downstream operations, as explained in Note 18 to the Consolidated Financial Statements. This change increased revenue. o Higher natural gas prices were more than offset by a decrease in crude oil prices due to weakening demand. Also impacting crude oil operating revenues were lower revenues from sour crude oil sales due to widening of the light/heavy crude oil differential and a higher proportion of lower value sour crude oil sales in 2001 (35% of total sales volumes versus 31% in 2000). The increase in sour crude oil production was primarily due to initial production from Project Millennium that could not be upgraded from sour to sweet crude oil until the hydrotreating units were commissioned late in 2001. Revenues were favourably impacted by a one-time $18 million pricing adjustment related to a large supply contract calculated retroactively to 1999. o Sales volumes for the year were unfavourably impacted by two maintenance shutdowns (one planned and one unplanned) at the Oil Sands operations that totalled 16 days. o Increased revenues of $99 million were associated with a crude oil business that commenced in 2001 to generate additional income by buying and selling production of other companies. The purchase of the crude oil for resale is shown in purchases of crude oil and products in the Consolidated Financial Statements. This activity did not have a significant impact on earnings or cash flow in 2001. The purchases of crude oil and products increased year-over-year by $584 million. This increase includes the impact, as noted above, of the change in accounting methodology for sales of $473 million between upstream and downstream operations. Costs for crude oil and other product purchases also increased due to a number of factors: o As noted above, Suncor initiated a business which purchased third party crude oil for resale. o Two maintenance shutdowns at the Sarnia refinery resulted in higher product purchases being incurred to meet customer commitments. o Two maintenance shutdowns at Oil Sands, which halted production for a total of 16 days, also resulted in more third party purchases of crude oil by the Sarnia refinery. o Higher natural gas costs and volume increases were associated with the retail marketing of natural gas in Ontario. These cost increases were partially offset by a reduction in the cost of crude oil and refinery feedstocks purchased from third parties due to a 14% decline in the benchmark WTI crude oil price in 2001 from 2000. Operating, selling and general expenses increased to $1,010 million in 2001, up from $918 million in 2000. The increase was primarily due to: o Higher refining costs reflecting increased energy costs and higher maintenance costs associated with two maintenance shutdowns at the Sarnia refinery. o Lower foreign exchange gains in 2001 with respect to the Stuart Oil Shale Project. 24 SUNCOR ENERGY INC. o Higher compensation, including a $10 million cost associated with the long-term compensation program (as described in Note 12(b) to the Consolidated Financial Statements). o Higher mining costs due to increased production and ore variability. o Higher research and development costs with respect to new technology assessments. The above factors were partially offset by lower production costs in Suncor's Natural Gas business due to the 18% production decline in 2001 compared to 2000, and lower costs associated with the Stuart Oil Shale Project in 2001, compared to 2000 due to divestment of this project in April 2001. In 2002 insurance costs are expected to increase by an estimated $14 million (175%). The increase primarily reflects higher premiums on property and business interruption insurance due to the tightening of insurance market capacity. As noted in Note 14(b) to the Consolidated Financial Statements, the deductible limit for the business interruption policy will be increased to $415 million (US$260 million) for 2002 from $70 million (US$45 million) in 2001. Exploration expenses decreased by $31 million in 2001, primarily as a result of lower dry hole costs. Royalty expenses decreased by $65 million in 2001 to $134 million. The decrease was primarily due to a lower Crown royalty rate for Oil Sands production, which was reduced to 1% of gross revenue compared to 5% in 2000 and lower Natural Gas sales levels. These favourable factors were partially offset by higher royalties due to higher natural gas prices and increased production from Oil Sands. Depreciation, depletion and amortization (DD&A) decreased by $5 million to $360 million in 2001 from $365 million in 2000. The decrease was primarily due to an $8 million decrease in DD&A in the Natural Gas business as a result of the 2000 asset divestment program. Most of the Project Millennium assets at Oil Sands will be depreciated over 40 years. Over the life of the assets, depreciation will average $90 million per year, with higher depreciation in the initial years and lower depreciation in the later years. In 2002 depreciation will be approximately $115 million. Overburden amortization is expected to increase in 2002 to approximately $160 million (pre-tax). Interest costs (before capitalization of interest on projects) increased in 2001 to $143 million, from $112 million in 2000, primarily reflecting higher debt levels, partially offset by lower variable interest rate costs. Long-term borrowings at the end of 2001 were $3.1 billion, up from $2.2 billion at the end of 2000, reflecting expenditures of approximately $1 billion on Project Millennium in 2001. With Project Millennium commencing commercial operations in CONSOLIDATED FINANCIAL RESULTS
($ millions) 2001 2000 1999 Net earnings 388 377 186 Cash flow provided from operations 831 958 591 Investing activities 1 680 1 607 1 290 Dividends - common shares 75 75 75 - preferred securities 48 47 37 Long-term borrowings 3 113 2 192 1 306 - ----------------------------------------------------------------
INDUSTRY INDICATORS
(average for the year unless otherwise noted) 2001 2000 1999 West Texas Intermediate (WTI) crude oil US$/barrel at Cushing 25.90 30.25 19.30 Canadian 0.3% par crude Cdn$/barrel at Edmonton 39.34 44.56 27.50 Light/heavy crude oil differential US$/barrel - WTI @ Cushing/Bow River @ Hardisty 9.51 6.84 3.42 Natural gas US$/thousand cubic feet at Henry Hub 4.38 3.90 2.27 Natural gas (Alberta spot) Cdn$/thousand cubic feet at Empress 6.31 5.08 3.00 Canadian natural gas exports to the U.S., trillions of cubic feet 3.8* 3.60 3.40 New York Harbour 3-2-1 crack US$/barrel** 4.42 5.45 2.47 Refined product demand (Ontario) percentage change over prior year (1.6)* 2.6 3.8 Exchange rate: Cdn$:US$ 0.64 0.67 0.67 - ------------------------------------------------------------------------------------------------------------------
* Estimate ** New York Harbour 3-2-1 crack is an industry indicator measuring the margin on a barrel of oil for gasoline and distillate. It is calculated by taking 2 times the New York Harbour gasoline margin plus 1 times the New York Harbour distillate margin and dividing by 3. 2001 ANNUAL REPORT 25 2002, interest charges that were capitalized in 2001 will now be expensed in 2002, thereby reducing 2002 earnings. Interest capitalized on Project Millennium in 2001 was approximately $120 million. Net interest costs increased from $8 million in 2000 to $18 million in 2001 primarily due to the costs associated with the Stuart Oil Shale Project. Subsequent to year-end, Suncor issued US$500 million of 7.15% unsecured notes due 2032 from a US$1 billion unallocated shelf prospectus. The net proceeds from the sale were used to repay commercial paper and bank borrowings. Following this transaction, Suncor had approximately $2,050 million of fixed rate borrowing at an average cost of 6.7%. The balance of Suncor borrowings are at floating interest rates. Short-term floating interest rates are at historical lows and total interest expense will be influenced by changes in short-term rates. Financing costs in 2002 could also be higher or lower due to foreign exchange gains or losses as the January 2002 debt issued will be restated ("marked-to-market") at the prevailing exchange rate between the Canadian and U.S. dollar. This could create volatility in earnings. It is anticipated that a $0.01 change in the exchange rate would have an estimated $5 million pre-tax impact on earnings with respect to the U.S. dollar denominated debt. Interest expense will be influenced by the company's anticipated change in its debt portfolio. For the past few years a high percentage of Suncor's debt was at floating interest rates. With the completion of Project Millennium, Suncor intends to replace bank debt with longer-term fixed rate public market debt. During 2001 Suncor issued $500 million medium-term notes as well as the above noted U.S. debt issue in early 2002. Subsequent to year-end, Suncor has also filed a shelf prospectus with Canadian securities regulatory authorities, enabling it to issue up to a further $500 million in medium-term notes in Canada if required. Suncor plans to manage the fixed versus floating rate exposure with the use of interest rate swaps. Taxes, other than income taxes, increased by $6 million to $367 million primarily due to higher sales volumes of taxable products (mainly transportation fuels) in Sunoco. Suncor's effective income tax rate in 2001 was 24%. This includes favourable adjustments of $43 million (9%) for provincial tax rate reductions and $9 million (1%) for federal tax rate reductions related to revaluation of opening future income tax balances. In 2000 the effective income tax rate was 39%, including $13 million (2%) in favourable provincial tax rate adjustments related to revaluation of opening future income tax balances. Also, in 2001 there was the recognition of lower provincial taxes of $6 million due to provincial deductibility of Crown royalties in excess of the federal resource allowance deduction. This deduction reduced the 2001 effective rate by 1%. In 2000 there was a similar provincial reduction of $13 million, which reduced the effective tax rate by 2%. Suncor believes its effective tax rate in 2002 will be approximately 38%. Based upon the prior year's capital investment levels and planned future investment levels, Suncor does not expect its upstream operations to be cash taxable until the latter half of the current decade. This assessment can change depending upon such factors as profitability and capital investments. DIVIDENDS During 2001, Suncor's quarterly common share dividend was $0.085 per share, unchanged from 2000. Dividend levels are reviewed quarterly in light of Suncor's growth-related initiatives, financial position, financing requirements, cash flow and other factors considered relevant by the Board of Directors. CORPORATE OFFICE EXPENSES Corporate office after-tax expenses decreased to $92 million in 2001 from $117 million in 2000. Operational expenses in 2001 exclude the $3 million write-down of the investment in the Stuart Oil Shale Project and a $7 million unfavourable provincial income tax rate adjustment. Operational expenses in 2000 exclude an $80 million write-down of the Stuart Oil Shale Project. Excluding these factors, the increase in operational expenses in 2001 to $82 million from $37 million in 2000 was primarily due to lower foreign exchange gains, higher research and development costs with respect to new technology assessments, higher compensation costs including the costs associated with the company's long-term compensation program and higher interest costs. The corporate centre had a net cash deficiency of $165 million in 2001 compared to a net cash deficiency of $76 million in 2000. The increase was primarily due to settlement in 2001 of outstanding 2000 obligations and income tax refunds expected to be received in 2002. 26 SUNCOR ENERGY INC O U T L O O K Suncor recognizes that operational excellence is important to achieving improved financial returns. Safe and efficient operations reduce the risk of production loss, environmental liability and the higher costs incurred in conducting unscheduled maintenance. In 2002, all of Suncor's businesses plan to continue to focus on base business excellence to improve operational reliability. Plans to apply technological advancements that are intended to increase the efficiency of each business, reduce costs and improve environmental and safety performance will be a key focus. PRODUCTION GROWTH AT OIL SANDS Suncor plans to leverage its existing facilities and operational experience with the intention of increasing Oil Sands production in phases over the next decade. (See Oil Sands Overview page 30.) PROJECT MANAGEMENT Engineering, procurement and construction (EPC) of Suncor's planned major expansions will be managed directly by the company's newly created Major Projects group. Management believes direct control of EPC can assist Suncor to reduce costs and improve the efficiency of the transition between construction and operation. INTEGRATION Natural gas production and downstream marketing strategies will continue to be an important part of Suncor's corporate strategy. (See Natural Gas Overview page 36 and Sunoco Overview page 40.) SUSTAINABILITY As the company expands its hydrocarbon-based businesses, management believes Suncor must also work toward the development of renewable energy. Renewable energy has the potential to reduce environmental impacts and create additional business investment opportunities. As part of the company's plans to invest $100 million in renewable energy projects by 2005, the SunBridge Wind Power Project was constructed in 2001. SunBridge is a $20 million partnership (50:50) between Suncor and Enbridge Inc. Suncor's effort to reduce greenhouse gas emissions is reflected in its pursuit of greater internal energy efficiency - with the dual objective of cost savings and improved environmental performance. Suncor also plans to invest in emissions offsets and carbon capture research and development. The company's goal is to align operations with relevant national and international commitments to limit greenhouse gas emissions. Workplace health and safety will remain a priority at all Suncor businesses and work sites. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE The issues Suncor must manage include, but are not limited to commodity prices, environmental regulations and regional labour issues including those specific issues discussed under Risk/Success Factors Affecting Performance for each Suncor business. Suncor believes that while the planned increases in Oil Sands production will provide strategic advantages, they also present issues that will require prudent risk management. COMMODITY PRICES Suncor's future financial performance remains closely linked to hydrocarbon commodity prices, which can be influenced by global and regional supply and demand, worldwide political events and the weather. These factors, among others, can result in a high degree of price volatility. In the last three years for example, the industry has seen the monthly average price for benchmark WTI crude oil range from a low of US$12 per barrel to a high in 2000 of US$34.25 per barrel. During the same period, the natural gas Henry Hub benchmark monthly average price ranged from a low of US$1.69 per thousand cubic feet (mcf) to a high of US$9.79 per mcf. Crude oil and natural gas prices are based on a U.S. dollar benchmark that results in Suncor's earned prices being influenced by the Canadian/U.S. currency exchange rate, thereby creating another element of uncertainty for the company. The continued weakness in the Canadian dollar versus the U.S. dollar in 2001 increased Suncor's revenues and earnings, as measured in Canadian dollars. In the future, Suncor's revenues will continue to be influenced by the value of the Canadian dollar relative to foreign currencies. 2001 ANNUAL REPORT 27 HEDGING Suncor cannot control or accurately predict the prices of crude oil or natural gas, or currency exchange rates. For this reason, the company has a hedging program that fixes the prices of crude oil and natural gas for a percentage of Suncor's total production. Suncor has entered into a foreign exchange contract for 2002, but currently has no plans to enter into foreign exchange contracts beyond 2002. Suncor's risk management objective with its hedging program is to lock in prices on a portion of the company's future production to reduce its exposure to market volatility and support the company's ability to finance growth. Refer to Note 17(b) to the Consolidated Financial Statements for details of revenue hedges. The Audit Committee and the Board of Directors meet with management regularly to assess Suncor's hedging thresholds in light of its price forecast and cash requirements. To add more certainty to Suncor's ability to finance future capital programs and repay debt, the Board authorized hedging up to 30% of the company's crude oil volumes between 2003 and 2006. In 2001, hedging decreased Suncor's earnings by $148 million. In 2000, hedging decreased earnings by $259 million. ENVIRONMENTAL REGULATION RISK/SUCCESS FACTORS Environmental legislation affects nearly all aspects of Suncor's operations. Environmental legislation imposes certain standards and controls on activities relating to mining, oil and gas exploration, development and production and the refining, distribution and marketing of petroleum products and petrochemicals and requires companies engaged in those activities to obtain necessary permits to operate. Also, environmental assessments and approvals are required before initiating most new projects or undertaking significant changes to existing operations. In addition to these specific known requirements, Suncor expects changes to environmental legislation will likely impose further requirements on companies operating in the energy industry. Some of the issues include the possible cumulative impacts of oil sands development in the Athabasca region; the need to reduce or stabilize various emissions; issues relating to global climate change, including the potential impacts of government regulation; land reclamation and restoration; water quality; and reformulated gasoline to support lower vehicle emissions. Changes in regulation could have an adverse effect on Suncor in terms of product demand, product formulation and quality, methods of production and distribution and operating costs. The complexity of these issues makes it difficult to predict their future impact on the company. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. [GRAPHIC DESCRIPTION] 2002 2003 2004 2005 2006 CRUDE OIL HEDGING PROGRAM (at December 31, 2001) Thousands of barrels per day 84 44 11 15 -- (kbpd) of Annual Crude Oil Hedged Current Annual Limits (kbpd) 105 66 68 68 68 Percentage of Annual 40 20 5 7 0 Crude Oil Hedged Hedged Price - Cdn$ per 31.99 33.44 33.44 34.37 -- barrel OTHER FACTORS Other critical factors affecting Suncor's financial results include volumes and margins of refined product sales, success of the natural gas exploration and development program, interest rates and the company's ability to manage both day-to-day operating costs as well as project costs. For further discussions of possible risk factors and uncertainties which may affect the company, refer to page 44 at the end of the MD&A and to the company's Annual Information Form, on file with securities regulators or available from the company. SENSITIVITY ANALYSIS The following sensitivity analysis shows the main factors affecting Suncor's annual pre-tax cash flow from operations and after-tax earnings based on actual 2001 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2001 results. With Project Millennium commissioning complete, Oil Sands production is expected to increase over 2001 levels and thus the sensitivity analysis on a 1,000 barrel per day change in production may not be indicative of future results. A change in any one factor could compound or offset other factors. LIQUIDITY AND CAPITAL RESOURCES Suncor's growth has been funded by a combination of internally generated funds and increased debt. Net debt increased to $3.1 billion at the end of 2001, approximately $900 million higher than at the end of 2000. 28 SUNCOR ENERGY INC. SENSITIVITY ANALYSIS
APPROXIMATE CHANGE IN PRE-TAX CASH FLOW FROM AFTER-TAX 2001 AVERAGE CHANGE OPERATIONS EARNINGS ($ millions) Oil Sands Price of crude oil ($/barrel) 29.17 US$1.00 35 25 Sweet/sour differential ($/barrel) 8.29 US$1.00 19 13 Sales (barrels/day) 121 500 1 000 10 7 Natural gas Price of natural gas ($/thousand cubic feet) 6.09 0.10 5 3 Production of natural gas (millions of cubic 177 10 15 6 feet/day) Sunoco Retail gasoline margin (cents/litre) 6.6 0.1 2 1 Refining/wholesale margin (cents/litre) 5.7 0.1 3 2 Consolidated Exchange rate: Cdn$:US$ 0.64 0.01 14 10 Interest rate 2.7%* 1% 2 1 - -----------------------------------------------------------------------------------------------------------
* Borrowings with interest at variable rates averaging 2.7% at December 31.
PLANNING ASSUMPTIONS 2001 ACTUAL Current Plan Last Year's Plan AVERAGE FOR Average next Average next THE YEAR 3-year range 3-year range Crude oil - WTI US$ per barrel 25.90 19.00 - 21.00 18.00 - 19.00 Natural gas - US$/thousand cubic feet @ Henry Hub 4.38 3.00 - 3.45 3.00 - 3.50 Exchange rate: Cdn$:US$ 0.64 0.65 - 0.69 0.69 - 0.71 - -----------------------------------------------------------------------------------------------------------
The above are planning assumptions and are not estimates or predictions of actual future events or circumstances. Because this table does not incorporate potential cross-relationships, it would not necessarily accurately predict future results. With the completion of Project Millennium, capital and exploration investment activity is planned to decrease to $900 million in 2002, down from $1.7 billion in 2001 and $2 billion in 2000. Suncor plans to make debt reduction one of its priorities as it prepares for the next stages of growth. Management believes a phased approach to future growth projects should improve the ability to manage project costs, providing further opportunities for debt reduction. This approach, along with anticipated higher Oil Sands sales levels and the hedging of approximately 50% of crude oil production in 2002, should allow for the reduction in both the absolute debt level and the net debt/cash flow provided from operations ratio. Suncor's target for this ratio is in the range of 1.5 to 2.0 times at mid-cycle pricing. At the end of 2001 this ratio was 3.8 times, higher than the expected 2001 short-term peak of 3.5 times Suncor targeted last year. The increase was due to the higher than estimated Project Millennium spending. Other key factors that can contribute to a reduction in this ratio are operational performance and crude oil prices, and to a lesser degree natural gas prices and downstream margins. Management does not expect crude oil prices will be sustained at the average level achieved in 2001. Suncor's business plans are based upon assumptions, including a crude oil price assumption lower than the 2001 WTI average price per barrel of $25.90. Based on current planning and operational assumptions, Suncor believes net debt could be reduced by $200 to $400 million in 2002, reducing the net debt to cash flow provided from operations ratio to the two times range in 2002. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 RATIO OF NET DEBT/ CASH FLOW PROVIDED FROM OPERATIONS Number of Times 1.4 2.2 2.3 2.3 3.8 Ratio could decline over the next two years depending upon such factors as commodity price assumptions and the integration of Project Millennium. 2001 ANNUAL REPORT 29 O I L S A N D S O V E R V I E W Suncor's Oil Sands business, located near Fort McMurray, Alberta, is the cornerstone of the company's growth plans. The business mines oil sands, extracts the bitumen and upgrades it into a variety of refinery feedstocks and diesel fuel. Relative to conventional oil exploration and production, oil sands reserves and recovery rates are generally better defined and more predictable, providing Suncor with what management believes is a more stable foundation for production growth. Oil Sands strategy for profitable growth is based on: o Applying proven as well as new technologies to increase oil production. o Reducing costs through application of technologies, economies of scale, direct management of growth projects and more efficient operations. o Building strategic business relationships to mitigate risk and capture value from the production of energy, steam and by-products. o Implementing growth in a manner that supports Suncor's vision of becoming a sustainable energy company. Oil Sands progressed this strategy in 2001 by commissioning Project Millennium, a $3.4 billion expansion that nearly doubled Oil Sands production capacity to 225,000 barrels per day (bpd) and improved operational flexibility by adding a second upgrader. This expansion is expected to reduce operating costs through process improvements and economies of scale. In 2001 Suncor received regulatory approval for the Firebag IN-SITU Oil Sands Project, a commercial scale in-situ project planned to supply an additional 140,000 barrels of bitumen per day by the end of the decade. Also in 2001, Suncor announced plans for Project Voyageur, which call for a staged expansion of Suncor's oil sands and in-situ facilities. Suncor has initiated the consultation process for the project and plans to apply for regulatory approval in late 2002. Voyageur requires approval of regulators and Suncor's Board of Directors, as well as development of engineering, construction and production plans for each phase and favourable fiscal and market conditions. Any expansion decisions will be aligned with the company's long-term marketing strategies. To support increased production, Suncor is working with other companies at the Oil Sands plant site. In 2001, TransAlta Energy Corporation commenced operation of its COGENERATION facility at the plant. A portion of the energy from the facility will help meet current energy needs of the Oil Sands operation while mitigating fluctuating energy costs and lowering carbon dioxide emissions per unit of production. RESULTS OF OPERATIONS AND INVESTING ACTIVITIES 2001 VS 2000
Oil Sands - Summary of Results ($ millions unless otherwise noted) 2001 2000 1999 Revenue 1 385 1 336 889 Production (thousands of bpd) 123.2 113.9 105.6 Average sales price ($/barrel) 29.17 31.67 23.84 Operational earnings 342 324 167 Net earnings 283 315 167 Cash flow provided from operations 486 655 405 Total assets 6 409 5 079 3 178 Investing activities 1 476 1 715 1 085 ROCE(%) 20.1 22.8 12.9 ROCE (%)* 6.4 10.6 9.2 - ----------------------------------------------------------
* ROCE- Return on average capital employed. Includes capitalized costs related to major projects in progress. IN-SITU In-situ refers to methods of extracting heavy oil from deep deposits of oil sands through horizontal drilling with minimal disturbance of the ground cover. COGENERATION The simultaneous production of electricity and steam from one energy source. 30 SUNCOR ENERGY INC. REVISED COST ESTIMATES FOR GROWTH PROJECTS The capital cost of Suncor's Project Millennium was approximately $3.4 billion, a $1.4 billion increase over the original 1997 estimate of $2 billion. The capital cost increased primarily as a result of higher labour, fabrication and material costs and changes in project scope. The additional capital costs were financed through internally generated cash flow and additional borrowing. When combined with an associated expansion of Suncor's upgrader, the first phase of the Firebag In-situ Oil Sands Project is expected to cost about $1 billion. This estimate is $250 million higher than Suncor estimated in 1999 when planning on the project was first initiated. The revised estimate reflects construction of additional common infrastructure to support subsequent stages of Firebag, future capacity improvements of the company's upgrader and other costs reflecting Suncor's experience with construction on Project Millennium. NET EARNINGS ANALYSIS OIL SANDS EARNINGS DECREASE 10% Oil Sands net earnings were $283 million in 2001, compared with $315 million in 2000. Operational earnings of $342 million in 2001 exclude a $31 million favourable income tax rate reduction and $90 million in Project Millennium start-up expenses. Operational earnings in 2000 were $324 million. The increase in operational earnings of $18 million in 2001 was primarily due to higher volumes and lower Crown royalty payments, offset by higher costs and an 8% decrease in crude oil prices from 2000. If the incremental start-up volumes had been excluded from the determination of 2001 operational earnings, it is estimated that operational earnings in 2001 would have been lower than in 2000. During 2001, Suncor initiated a new business to generate additional income by buying and selling the crude oil production of other companies. The purchase of crude oil for resale, $96 million in 2001, is shown in the purchases of crude oil and products line in the Consolidated Financial Statements. These activities did not have asignificant impact on earnings or cash flow. OIL SANDS CRUDE OIL PRICES DECREASE 8% Oil Sands crude oil prices in 2001 averaged $29.17 per barrel, compared with $31.67 per barrel in 2000. WTI benchmark prices decreased 14% to an average of US$25.90 per barrel in 2001 from an average of US$30.20 per barrel in 2000. Price was further negatively impacted by wider sweet and sour differentials combined with a proportionately higher volume of lower value sour crude sales. The effect of a lower crude price was partially offset by decreased hedging losses of $224 million in 2001, compared with $407 million in 2000. The combined impact of the above pricing factors reduced earnings in 2001 by $65 million after-tax from 2000 levels. OIL SANDS PRODUCTION INCREASES 8% Oil Sands increased production in 2001 for the ninth consecutive year to an average of 123,200 bpd, up from 113,900 bpd in 2000, mostly due to the startup of Project Millennium in the fourth quarter. With the Millennium upgrading facilities in operation, production averaged a record-breaking 180,000 bpd in December 2001. [GRAPHIC DESCRIPTION] BRIDGE ANALYSIS OF NET EARNINGS (Cdn$millions) Total 315 2000 Volume 40 Oil Price (65) Royalties 44 Cash Expenses (10) Tax Adjustment 9 - - Other Earnings Before the Following 333 Millennium Start-up (81) Tax Adjustments* 31 Total 283 2001 Lower crude price and increased costs associated with start-up of Project Millennium, partially offset by record sales volume and decreased royalties and income taxes, resulted in a 10% decrease in earnings. * Provincial income tax rate adjustment on opening future tax balances. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 PRODUCTION (thousands of bpd) Actual 79.4 93.6 105.6 113.9 123.2 Oil Sands achieved record production of 123,200 bpd in 2001. As the new Millennium facilities are fully integrated with base operations, Oil Sands expects production to average 210,000 bpd in 2002. 2001 ANNUAL REPORT 31 Production in 2001 was impacted by a planned MAINTENANCE SHUTDOWN of the fractionating tower in the second quarter that halted production for a total of nine days and an unscheduled seven-day maintenance shutdown of the same facility in the fourth quarter. Higher sales levels in 2001 resulted in a year-over-year earnings improvement of $40 million. Because production commenced from Millennium upgrading facilities before the hydrotreating units were fully commissioned, sour crude inventories increased in late 2001. The sour crude inventory is expected to be reduced in the first half of 2002. Since the majority of the anticipated future incremental production from Project Millennium is expected to be upgraded sweet crude, an improved crude sales mix is expected in 2002. Oil Sands is targeting production of approximately 55% light sweet crude, 12% diesel and 33% light sour crude in 2002 compared to the 2001 mix of 46% light sweet crude, 12% diesel and 42% light sour crude. ROYALTIES Crown royalties in effect for Suncor's existing Oil Sands operations require payments to the Government of Alberta of 25% of net revenues less allowable costs (including capital expenditures), subject to a minimum payment of 1% of gross revenues, a rate that Suncor expects to pay until 2009. This expectation is based on assumptions relating to future oil prices, production levels, operating costs and capital expenditures. In 2001 Oil Sands made royalty payments of 1% of gross revenues, compared to 5% in 2000. Crown royalties payable by Suncor to the Government of Alberta decreased to $15 million in 2001 from $87 million in 2000 as a result of the 1% royalty rate and lower commodity prices that were only partially offset by higher sales levels. The lower Crown royalties were partially offset by a $4 million increase in royalties paid to Anadarko Petroleum Corporation (Anadarko) due to more tonnes mined in 2001 from the lease on which Anadarko has a royalty interest. Mining on the lease is expected to be completed in 2002. The decrease in total royalties expensed increased earnings by $44 million after-tax. EXPENSES INCREASED Cash expenses of $493 million in 2001 increased by 3% over 2000 levels, reducing Oil Sands earnings by approximately $10 million after-tax. The increase in expenses was a result of higher energy costs driven by higher natural gas prices, higher sales volumes and higher mining costs, including the costs associated with minimizing the impact of ore variability. Non-cash charges (depreciation, depletion and amortization) remained flat year-over-year due to offsetting factors. PER BARREL OPERATING COSTS Cash operating costs, excluding $5.10 per barrel Project Millennium start-up and OVERBURDEN removal expenditures, decreased to $11.90 per barrel in 2001. This compares to $12.55 in 2000 (excluding $1.00 per barrel in Project Millennium start-up and overburden removal costs in 2000). The decrease of $0.65 per barrel is due to higher volumes, partially offset by higher energy costs. Not all the expenses associated with the additional volumes from Project Millennium are included in the $11.90 per barrel cash operating cost. As a result, the $11.90 per barrel cash operating cost is not indicative of cash operating costs in the future. Total cash and non-cash operating costs per barrel in 2001 were $14.50 ($19.60 including Project Millennium start-up and overburden removal expenses), compared with $16.25 per barrel ($17.25 per barrel including Project Millennium [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 CASH AND TOTAL OPERATING COSTS (Cdn$ per barrel) Cash Operating Cost 13.25 11.75 11.70 12.55 11.90 Start-up Expenditures -- -- -- 1.00 5.10 Project Millennium Total Cash Cost 13.25 11.75 11.70 13.55 17.00 Non-cash Cost 2.55 2.25 3.35 3.70 2.60 Total 15.80 14.00 15.05 17.25 19.60 Total cash costs increased due to higher energy costs and Project Millennium start-up expenditures. Non-cash expenses decreased due to reduced maintenance shutdown amortization costs resulting from deferral of a maintenance shutdown to 2002. MAINTENANCE SHUTDOWN Preventative maintenance activities that involve shutting down major parts of a facility or an entire facility. OVERBURDEN Surface material that must be removed before mining. Consists of muskeg, glacial deposits and sand. 32 SUNCOR ENERGY INC. expenses) in 2000. The $1.75 per barrel decrease in total operating costs (excluding Project Millennium expenses) was due to the same factors affecting cash operating costs. Oil Sands cash operating margin was $11.50 per barrel in 2001, compared with $15.80 per barrel in 2000. The following factors influenced cash margins during the year: o Lower crude prices (before hedging) had an unfavourable impact of $7.10 per barrel. o Lower hedging losses had a favourable net impact of $4.60 per barrel. o Cash operating costs had a favourable impact of $0.65 per barrel. o Project Millennium start-up and overburden removal expenditures had an unfavourable impact of $4.10 per barrel. o Lower royalties had a favourable impact of approximately $1.65 per barrel. NET CASH DEFICIENCY ANALYSIS Cash flow provided from operations was $486 million in 2001, compared with $655 million in 2000. The decrease of $169 million was primarily due to lower earnings resulting from Project Millennium's $141 million start-up expenses in 2001, $126 million higher than 2000 spending. Higher overburden removal expenditures (mostly related to Project Millennium) of $119 million, compared to 2000 expenditures of $75 million, a $10 million increase in reclamation spending to $22 million, and recognition of the estimated employee long-term compensation program payment in the amount of $16 million were other factors that reduced cash flow provided from operations compared to 2000 by $43 million. Oil Sands working capital increase in 2001 was $35 million, compared to $169 million increase in 2000. This reduction is primarily due to lower trade receivables in 2001, reflecting lower crude oil prices. The reduction was partly offset by higher inventory levels and lower accounts payable and accruals, reflecting completion of Project Millennium, offset partially by an increase in current liabilities resulting from recognition of the estimated employee long-term compensation program payment. Capital investment at Oil Sands decreased to approximately $1.5 billion in 2001 from approximately $1.7 billion in 2000. The $239 million decrease was primarily due to lowerspending on Project Millennium. These combined factors resulted in a decrease in net cash deficiency from $1.2 billion in 2000 to approximately $1 billion in 2001. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 OPERATING MARGINS (Cdn$ per barrel) Selling Price 26.36 22.18 23.84 31.67 29.17 Cash Margin 12.05 9.25 10.75 15.80 11.50- 16.80 16.60 SELLING PRICE - The average price from the sale of crude oil, including the impact of hedging activities. CASH MARGIN - The difference between the selling price received for products sold and cash operating cost per barrel plus royalties per barrel. [GRAPHIC DESCRIPTON] 2000 2001 BRIDGE ANALYSIS OF NET CASH 0 DEFICIENCY (Cdn$ millions) Total (1 229) Operations (43) Working Capital 134 Investing Activities 239 Cash Flow Before the Following (229) Project Millennium (126) Total (1 025) Lower capital spending on Project Millennium and a decrease in working capital mainly due to lower trade receivables were partially offset by decreased cash flow from operations and expenses associated with start-up of Project Millennium. 2001 ANNUAL REPORT 33 O U T L O O K The foundation of Oil Sands growth plans is the large resource base estimated to be in place on Suncor leases. Independent estimates place total Oil Sands resources at 12 billion barrels, including PROVED AND PROBABLE RESERVES that are estimated at 4.4 billion barrels. Suncor's future plans for Oil Sands are a continuation of the company's current plans and strategic drivers. The company's focus remains on activities expected to increase production, decrease operating costs and improve environment, health and safety performance. INCREASE PRODUCTION Oil Sands expects production to average approximately 210,000 bpd in 2002 as the new Millennium facilities are fully integrated with base operations. This production goal assumes a 28-day maintenance shutdown will take place during the year. Management will look at the potential to defer the shutdown to 2003. Construction on the first phase of the Firebag In-situ Oil Sands Project, including approved upgrader expansions, is scheduled to continue in 2002. Twenty steam assisted gravity drainage (SAGD) well pairs for Stage 1 are scheduled for drilling during the year. Production facility modules are under construction and installation is scheduled to begin at the site in the second quarter of 2002. Spending in 2002 for this work is currently estimated at $420 million. In-situ production from the first phase of Firebag and upgrader expansions is expected to bring Oil Sands production capacity from 225,000 bpd to a daily average of 260,000 bpd in 2005. In 2002 Suncor will consult with stakeholders in creating detailed plans for engineering, design and project development for Project Voyageur. Voyageur is planned to further expand Suncor's oil sands and in-situ developments, building on the benefits of both types of operations to increase production. Assuming production of 260,000 bpd has been reached by 2005, Voyageur phase one is being planned to increase production capacity to the range of 400,000 to 450,000 bpd in 2008. Current phase two plans call for additional processing units to reach a target production capacity of 500,000 to 550,000 bpd in 2010 to 2012. Preliminary cost estimates for Voyageur will be made late in 2002. Development requires regulatory approval, and is subject to other conditions mentioned on page 30. A Sustainability Legacy program will be integrated into planning for Voyageur with an objective of mitigating increases in air emissions, reducing water use and discharge, accelerating reclamation and limiting land disturbance. The Sustainability Legacy program also plans to examine ways Suncor can support training and apprenticeship programs and help neighbouring communities benefit from the growth of the oil sands industry. Currently, there are no cost estimates for this program. REDUCE OPERATING COSTS Management believes that debottlenecking and efficiency and reliability improvements provide an opportunity to further reduce the cash operating cost per barrel. Management will work towards its objective of achieving cash operating costs of $8.50 to $9.50 (approximately US$6) per barrel, though - -------------------------------------------------------------------------------- PROVED AND PROBABLE RESERVES Annual estimates are made by Suncor of recoverable bitumen reserves associated with company in-situ leases and of synthetic crude oil reserves associated with its mineable oil sands leases. The estimates are then allocated between proved and probable categories based upon criteria determined by management and reviewed by independent consultants. With proved reserves there is at least a 90% confidence the estimate will be exceeded. Probable reserves incorporate portions of both mining and in-situ (Firebag) Suncor leases that have a lower drilling density and are expected to be recovered under current approvals within a period of 30 years. There is at least a 50% chance the proved plus probable reserve estimates will be exceeded. The bitumen estimates are converted to crude oil estimates on the basis of yields currently being obtained. Resources include proved and probable reserves. These resources include quantities of oil and gas that are estimated, on a given date, to be potentially recoverable from known accumulations and undiscovered accumulations that are not proved or probable reserves. Resources are a higher risk and are generally believed to be less likely to be recovered than proved and probable reserves. Total resources include both synthetic crude oil estimates for mining leases, and bitumen estimates for in-situ oil sands leases. 34 SUNCOR ENERGY INC. attaining this objective will require achieving some of the improvements noted above and will depend on factors and assumptions such as natural gas costs at mid-cycle prices and higher production levels. In 2002 management believes cash operating costs could be in the $10 to $10.50 (US$6.50 to US$6.80) per barrel range. These targets and estimates are subject to certain risk factors and uncertainties discussed on page 44 under "Forward-looking Statement" and their achievement cannot be assured. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE The strategic advantages of Oil Sands growth include: o Economies of scale associated with higher levels of production from the existing Oil Sands infrastructure. o Parallel processing in the extraction and upgrading processes provide flexibility to schedule periodic plant maintenance while continuing to generate production from the remaining units. o The ability to leverage demonstrated operational experience and technologies. o Production growth without the level of exploration risk associated with conventional oil and gas operations. The issues Suncor must manage include, but are not limited to: o Suncor's ability to finance Oil Sands growth in a volatile commodity pricing environment. (Also refer to the section on Liquidity and Capital Resources on page 28.) o The ability to complete future oil sands projects both on time and on budget could be impacted by competition from other oil sands projects for skilled people, increased demands on the Fort McMurray, Alberta infrastructure (housing, roads, schools, etc.), or higher prices for the products and services required to operate and maintain the Oil Sands plant. Suncor continues to address these issues through a comprehensive recruitment and retention strategy, working with the community to determine infrastructure needs, designing Oil Sands expansion to reduce unit costs, seeking strategic alliances with service providers and tightening controls on engineering, procurement and project management. o Potential changes in the demand for refinery feedstocks and diesel fuel. Suncor believes it can reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding its customer base and offering customized blends of refinery feedstocks to meet customer specifications. The profitability of Suncor's Oil Sands business is influenced by world crude oil price levels. These prices are difficult to predict and impossible to control. In addition, the light/heavy oil differential can have an impact on earnings. In 2001, this differential widened and reduced earnings. Management believes the differential will trend toward more historical ranges in 2002 if the demand for heavy oil increases as anticipated. Unplanned production or operational outages and slowdowns, particularly those that are weather-related, can be expected. Suncor's relationship with employees and trade unions is important to the company's future success because work disruptions have the potential to adversely affect Oil Sands operations and growth projects. Suncor entered into a new three-year collective agreement with the Communications, Energy and Paperworkers Union, Local 707 effective May 1, 2001. Also refer to Risk/Success Factors Affecting Performance on page 27. 2001 ANNUAL REPORT 35 N A T U R A L G A S O V E R V I E W Suncor's Natural Gas business (NG) produces conventional natural gas in Western Canada, supplying it to markets throughout North America. The sale of NG production provides an internal hedge for Suncor's natural gas consumption. In 2001, NG continued to advance its strategy for profitable growth in order to maintain an INTERNAL HEDGE for Suncor's growing gas consumption. This strategy is built on four key platforms: o Focusing on natural gas. o Building competitive operating areas. o Improving base business efficiency. o Creating new low capital service offerings to the resource sector. NG's first service offering, Prospect Generation Services (PGS), was launched and generated net cash flow of $6 million in 2001 primarily through land sales. PGS develops prospects on new and existing non-core Suncor lands and markets those business opportunities to the resource sector. PGS earnings did not have a material impact on earnings in 2001. NET EARNINGS ANALYSIS NET EARNINGS INCREASE BY 19% Net earnings were $117 million in 2001, up 19% over the 2000 level of $98 million, primarily due to stronger natural gas prices and cost reductions. Operational earnings, which in 2001 exclude the impact of the adjustment related to revaluation of opening future provincial income tax balances ($9 million), asset divestments ($4 million) and restructuring charges ($1 million), increased by 75% from $59 million in 2000 to $103 million in 2001. This was primarily due to higher commodity prices and lower exploration and operating costs, partially offset by lower production volumes resulting from property divestments in 2000 and higher royalty expenses. Cash flow from operations rose to $280 million from $238 million in 2000, also a reflection of higher natural gas prices and lower costs. RESULTS OF OPERATIONS, INVESTING AND EXPLORATION ACTIVITIES 2001 VS. 2000 NATURAL GAS - SUMMARY OF RESULTS
($ millions unless otherwise noted) 2001 2000 1999 Revenue 449 428 306 Production (thousands boe/d) 33.4 40.5 51.1 Average sales price Natural gas ($/thousand cubic feet) 6.09 4.72 2.44 Natural gas liquids ($/barrel) 34.38 36.66 19.32 Crude oil ($/barrel) 33.92 29.50 20.94 Operational earnings 103 59 22 Net earnings 117 98 41 Cash flow provided from operations 280 238 172 Total assets 722 762 962 Capital and exploration expenditures 132 127 200 ROCE (%) 32.1 17.2 5.5 - -----------------------------------------------------------
In 2001, Suncor began to convert natural gas to barrels of oil equivalent (boe) at a 6:1 ratio (thousand cubic feet of natural gas:barrel of oil); previously, conversion was on a 10:1 basis. Figures for 1999 and 2000 have been restated on a 6:1 basis. - -------------------------------------------------------------------------------- INTERNAL HEDGE An internal hedge occurs when Suncor's natural gas production equals or is greater than internal consumption, providing the company protection from volatile natural gas prices in the North American market. 36 SUNCOR ENERGY INC. NATURAL GAS PRICES INCREASE 29% In 2001, NG's natural gas price averaged $6.09 per thousand cubic feet (mcf) of natural gas, compared with $4.72 per mcf in 2000. Increased prices in 2001 were a result of increased demand coupled with a relatively flat natural gas supply in North American markets. NG also benefited from higher than industry average exposure to the high value California market in 2001. While crude oil made up only 7% of NG's production in 2001, crude prices were also higher than 2000, averaging $33.92 per barrel (after hedging losses), compared to $29.50 per barrel (after hedging losses) in 2000. The price for natural gas liquids averaged $34.38 per barrel in 2001, compared to $36.66 per barrel in 2000. The combined impact of the above pricing factors increased earnings by $49 million. PRODUCTION DECLINES 17% FROM 2000 LEVELS NG's natural gas and liquids volumes declined to an average of 33,400 barrels of oil equivalent per day (boe/d), or 200 million cubic feet equivalent/day (mmcfe/d) in 2001, from an average of 40,500 boe/d or 243 mmcfe/d in 2000. The main reason for production declines was asset divestments associated with portfolio optimization during 2000. Production divestments of 10,600 boe/d at the time of sale were only partially offset by volume growth related to the 2001 capital spending program. The decrease in volumes resulted in a reduction in earnings of $28 million compared to 2000. ROYALTIES INCREASE Royalties increased to $8.56 per boe in 2001, from $6.81 per boe in 2000 due mainly to the increase in commodity prices. The increase in royalties resulted in a reduction in earnings of $2 million. [GRAPHIC DESCRIPTON] 2000 2001 BRIDGE ANALYSIS OF NET EARNINGS DEFICIENCY (Cdn$ millions) Total 98 Price (28) Volume Royalties (2) Expenses 25 Earnings Before the Following 142 Divestment Gains (65) Tax Adjustment* 9 Restructuring Costs 31 Total 117 Higher natural gas prices and lower expenses offset the decline in production from 2000 divestments. * Provincial income tax rate adjustment on opening future tax balances. [GRAPHIC DESCRIPTON] 1997 1998 1999 2000 2001 SUNCOR NG PRICING VS. INDUSTRY AVERAGE (Cdn$/thousand cubic feet) Suncor NG Average Annual Price 1.93 1.95 2.44 4.72 6.09 Industry Average Reference 1.98 1.95 2.47 4.53 5.39 Price 2001 Industry Average Reference Price is an estimate. [GRAPHIC DESCRIPTON] 2000 2001 BRIDGE ANALYSIS NET CASH SURPLUS (Cdn$ millions) Total 451 Operations 59 Capital and Exploration Expenditures (7) Divestment Proceeds (292) Total 211 Year-over-year decline of $240 million in NG's net cash flow reflected lower proceeds from property dispositions and slightly higher capital and exploration spending, partially offset by higher operating cash flows resulting from higher natural gas prices and lower expenses. [GRAPHIC DESCRIPTON] 1997 1998 1999 2000 2001 PRODUCTION (thousands of boe per day) Natural Gas 40.0 41.2 37.7 33.3 29.5 Liquids (natural gas liquids 15.7 16.3 13.4 7.2 3.9 and crude oil) Total 55.7 57.5 51.1 40.5 33.4 Although 2001 production was lower than 2000 due to property divestments, production exceeded 2001 goals by 1,000 boe/d, as NG continued bringing non-producing reserves to the producing stage. 2001 ANNUAL REPORT 37 TOTAL EXPENSES REDUCED FROM 2000 LEVELS Total expenses, excluding royalties and restructuring charges, were reduced by $49 million in 2001 from 2000 levels. Exploration expenses were down $31 million in 2001 due to a decrease in dry hole costs. Operating expenses decreased by $10 million compared to 2000 levels due to asset divestments and improved base business efficiency. Non-cash expenses (depreciation, depletion and amortization) decreased by $8 million as a result of divestments in 2000. Combined, the above factors increased earnings by $25 million year-over-year. In 2000, NG set a target to decrease annualized operating costs by a total of $18 million to $20 million by year-end 2001. Approximately $15 million of this target was reached in 2000. Annualized operating costs decreased an additional $5 million in 2001 through a focus on administrative cost controls and reduced lifting costs. ASSET DIVESTMENT GAINS In 2001, NG divested a non-core heavy oil property, recording a $4 million after-tax gain, compared to a $69 million gain in 2000 when the majority of NG's announced strategic divestments occurred. This resulted in a $65 million change year-over-year. RESTRUCTURING CHARGES In 2001, NG recorded a positive adjustment on restructuring charges that increased after-tax earnings by $1 million. In 2000, NG recorded restructuring charges that reduced after-tax earnings by $30 million for a year-over-year change of $31 million. TAX ADJUSTMENTS In 2001, earnings benefited from positive tax adjustments of $9 million. This reflects the impact of adjustments related to revaluation of opening future income tax balances. NET CASH SURPLUS ANALYSIS NG had a net cash surplus of $211 million in 2001, a decline of $240 million when compared to the net cash surplus of $451 million in 2000. This reduction was primarily due to a decrease in divestment proceeds of $292 million, partially offset by an improvement in cash from operating activities of $59 million. CAPITAL AND EXPLORATION INVESTING ANALYSIS During 2001, NG continued to focus on bringing proved undeveloped reserves into production. Capital expenditures were $132 million, higher than $127 million in 2000, due to increased expenditures on coalbed methane land acquisition and exploration. Divestment proceeds decreased $292 million as a result of completing the strategic divestment program in 2000. [GRAPHIC DESCRIPTION] 2001 DIRECT PROPRIETARY GAS SALES (69% of sales) (mmcf/d) (%) British Columbia 13 11 Midwest U.S. 15 12 Eastern Canada 21 17 California 40 33 Alberta 33 27 Total 122 100 [GRAPHIC DESCRIPTION] 2001 SYSTEM PROPRIETARY GAS (31% of sales) (mmcf/d) (%) TransCanada Gas Services 29 53 Pan Alberta 19 35 Canwest 2 3 Other 5 9 Total 55 100 [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 LIFTING AND ADMINISTRATION COSTS Administration 28 29 28 29 24 (Cdn$ millions) Lifting ($ per boe) 2.81 2.79 3.10 3.11 2.96 Total operating costs decreased from the prior year as Natural Gas maintained focus on controlling administrative costs and reducing lifting costs. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 TOTAL PROVED RESERVES (millions of barrels of oil equivalent) Natural Gas 182 200 168 133 125 Liquids 70 69 51 16 14 Total 252 269 219 149 139 Over the last two years, Natural Gas activities have been directed towards bringing non-producing reserves to the producing stage. 38 SUNCOR ENERGY INC. O U T L O O K PROFITABLE GROWTH NG has a goal of achieving a return on capital employed (after-tax earnings divided by average capital employed) of at least 12% in 2002 and 15% in 2004 at mid-cycle natural gas prices (US$3.00 to US$3.50/mcf price range) while producing volumes in excess of internal demand. Management will work toward this goal by building existing operating areas and developing new production and revenue streams. NG's production outlook for 2002 targets 180 mmcf/d to 190 mmcf/d of natural gas plus 1,800 bpd of natural gas liquids and 1,200 bpd of oil. Leveraging Suncor's expertise and assets in three core areas in western Alberta and northeastern British Columbia will continue to be the foundation for production and revenue in 2002. SUSTAINABILITY AND RENEWABLE ENERGY Suncor announced plans to place investments in renewable energy under the management of NG beginning in 2002. NG will manage and operate Suncor's renewable energy projects, but segmented financial data will be reported under Corporate results. This realignment is part of Suncor's strategy to provide hydrocarbon-based resources that meet the immediate energy needs of consumers while also pursuing the development of low-emission and no-emission energy sources that have a reduced environmental impact. In 2002, Suncor plans to continue to investigate wind power as an economically viable source of renewable energy. Incentives announced in Canada's federal budget late in 2001 should increase the attractiveness of wind power investments. Coalbed methane development may contribute to both increased volumes and reduced carbon dioxide (CO2) emissions. NG is participating in research and development initiatives to evaluate the potential of coalbeds to SEQUESTER CO2, a waste greenhouse gas emission. CO2 pumped into the coalbed may provide an economic means of increasing production of natural gas from the coalbed while reducing the company's net overall greenhouse gas emissions. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE Management continues to believe the single most important factor influencing NG's long-term performance is its ability to consistently and competitively find and develop reserves that can be brought on stream economically. Market demand for land and services can also increase or decrease operating costs. Management believes there are risks and uncertainties associated with obtaining regulatory approval for exploration and development activities. Working in other countries could increase these risks and add to costs or cause delays to these projects. These factors and estimates are subject to certain of the risks, assumptions and uncertainties discussed on page 44 under "Forward-looking Statement" and their achievement cannot be assured. Also refer to Risk/Success Factors Affecting Performance on page 27. - -------------------------------------------------------------------------------- SEQUESTER Sequester refers to the capture and storage of carbon dioxide, preventing its release to the atmosphere. 2001 ANNUAL REPORT 39 S U N O C O O V E R V I E W Suncor's wholly owned subsidiary Sunoco Inc. operates a refining and marketing business in central Canada. Its Sarnia, Ontario refinery has the capacity to refine 70,000 barrels per day of crude oil into gasoline, distillates and petrochemical products. Products are sold to wholesale, commercial and industrial markets and through a controlled retail network in Ontario. Sunoco's refining and marketing strategy is focused on: o Improving gross profit of refining assets. o Enhancing retail customer offering. o Creating long-term growth opportunities. o Supporting sustainable development. For the third consecutive year, Sunoco continued to show volume growth in refined product sales. In 2001, total sales averaged 93,400 barrels per day (bpd), representing an improvement of 1% from 2000. Sunoco's share of the total refined product sales in its primary market of Ontario was approximately 18%, compared to 17% in 2000. Approximately 59% of Sunoco's total sales volumes are marketed in Ontario through controlled retail networks. These include 302 Sunoco retail service stations, 18 Sunoco-branded Fleet Fuel Cardlock sites and two joint venture businesses comprised of 154 Pioneer-operated service stations, 47 UPI-operated retail service stations and bulk distribution facilities for rural and farm fuels. (Pioneer Group Inc. is an independent retailer with which Sunoco has a 50% joint venture partnership and UPI Inc. is a 50% joint venture company with GROWMARK Inc.) Approximately 38% of Sunoco's refined products were sold to wholesale and industrial accounts in Ontario and Quebec in 2001, primarily consisting of jet fuels, diesel and gasolines. The remaining 3% of Sunoco's refined products were petrochemicals sold through Sun Petrochemicals Company, a 50% joint venture between a subsidiary of Sunoco and a U.S. refinery. Sunoco also markets natural gas to approximately 125,000 commercial and residential customer accounts in Ontario. RESULTS OF OPERATIONS AND INVESTING ACTIVITIES 2001 VS. 2000 SUNOCO - SUMMARY OF RESULTS
($ millions unless otherwise noted) 2001 2000 1999 Revenue 2 588 2 604 1 779 Refined product sales (thousands of cubic metres) Sunoco retail gasoline 1 575 1 539 1 500 Total 5 419 5 360 5 080 Operational earnings 70 68 27 Net earnings (loss) breakdown: Rack Back 47 69 14 Rack Forward 23 (1) 13 Others (tax adjustments) 10 13 -- Total 80 81 27 Cash flow provided from operations 165 174 103 Investing activities 71 59 43 Net cash surplus 111 155 129 ROCE (%) 18.4 20.5 6.0
IN JANUARY 2002, SUNCOR'S DOWNSTREAM OPERATIONS WERE REORGANIZED AS ENERGY MARKETING AND REFINING. SEGMENTED RESULTS FOR 2001 ARE REPORTED UNDER THE SUNOCO NAME. 40 SUNCOR ENERGY INC. NET EARNINGS ANALYSIS NET EARNINGS REMAIN STEADY Sunoco's 2001 net earnings were $80 million, compared with $81 million in 2000. Operational earnings were $70 million, up from $68 million in 2000. Operational earnings in 2001 and 2000 exclude favourable income tax adjustments of $10 million and $13 million, respectively, related to revaluation of opening future provincial income tax balances. The higher operational earnings were due primarily to improved margins in the commercial and reseller channels, stronger profit from retail operations and retail natural gas business, and a 1% growth in sales volumes. Partially offsetting the favourable factors were lower refining margins, lower refinery production and higher expenses. Return on capital employed was 18.4%, compared to 20.5% in 2000. The reduction resulted from lower net earnings combined with a higher capital employed. LOWER REFINING MARGINS IMPACT RACK BACK RACK BACK operational earnings declined to $47 million in 2001, compared with $69 million in 2000, due primarily to lower refining margins, lower refinery production and higher expenses. Refining margins decreased to 5.7 cents per litre (cpl) in 2001, compared with 5.9 cpl in 2000. The lower margins were attributable to a decline in product demand resulting from a weakening economy. Net earnings decreased by $14 million due to lower refining margins and higher costs driven by increased product purchases. The refinery encountered a number of unplanned outages involving the catalytic cracker (in the first quarter, 2001) and the petrochemical and vacuum units (in the fourth quarter, 2001). As a result, the crudeutilization rate dropped to 92%, down 6% from 2000. Additional product purchases were made to satisfy customer demand due to the lower production. Sales volumes were 1% higher compared to 2000, averaging 14,800 cubic metres per day (93,400 bpd) from 14,600 cubic metres per day (92,200 bpd) in 2000. The higher sales volumes were comprised of the refinery's production, which was 4% lower than 2000, and purchases of finished products to meet customer demand. In the fourth quarter of 2001, the Sarnia refinery completed a planned maintenance shutdown. While a majority of the work was completed on schedule, there was a two-week extension to resolve catalyst problems. Rack Back's expenses were $22 million higher in 2001 compared with 2000, primarily as a result of higher natural gas prices and a 20% increase in natural gas consumption due to reduced fuel oil burning. The increase in expenses was partially offset by a gain of $9 million in 2001 from sales of excess supplies of natural gas initially bought for the retail natural gas marketing business. Due to changes in customer demand forecasting methodology, excess gas supply was identified and liquidated. Also impacting Rack Back's earnings was a $2 million earnings reduction from Sun Petrochemicals Company. RACK FORWARD EARNINGS UP $24 MILLION RACK FORWARD operational earnings increased to $23 million in 2001, compared to a loss of $1 million in 2000. The increase was attributable to stronger earnings from retail operations, commercial and reseller channels and improved retail natural gas margins. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 CRUDE UTILIZATION/ HIGH VALUE COMPONENTS (percentage) Crude Utilization 97 99 95 98 92 High Value Components 90 91 92 91 89 Sunoco's crude utilization rate declined 6% to 92% in 2001 due primarily to unplanned outages during the year. A planned maintenance shutdown was also completed in the fourth quarter. - -------------------------------------------------------------------------------- RACK BACK AND RACK FORWARD Sunoco's financial reporting in 2001 is based on its Rack Back/Rack Forward organizational structure and prior year results have been reclassified accordingly. The Rack Back division includes the procurement and refining of crude oil and feedstocks and sales and distribution to the Sarnia refinery's largest industrial and reseller customers. Rack Forward includes retail operations, retail natural gas marketing, cardlock and industrial/commercial sales, and the UPI and Pioneer joint venture businesses. 2001 ANNUAL REPORT 41 For the fourth consecutive year, gasoline sales at Sunoco's retail network increased. Retail gasoline volume improved by more than 2%, contributing to an earnings improvement of $2 million over 2000. While the retail gasoline margin remained unchanged from 2000 at 6.6 cpl in 2001, total fuel margins from the retail business improved by $4 million due to a more favourable product mix. ANCILLARY and royalty income was $4 million higher than 2000, reflecting continued expansion of non-fuel products and services in the retail network. These positive earnings impacts were partially offset by increased expenses of $7 million resulting from higher operating costs. In 2001, retail natural gas margins improved $10 million from 2000. The restructuring of customer contracts enabled Sunoco to match fixed price sales contracts with fixed price supply. In addition, commercial and reseller sales channels further improved Rack Forward earnings by $8 million due to margin improvement and $1 million related to volume growth. Net earnings from Sunoco's retail joint ventures with UPI and Pioneer were $2 million higher in 2001, reflecting stronger volumes and margins. NET CASH SURPLUS ANALYSIS Net cash surplus decreased to $111 million in 2001, compared with $155 million in 2000. This decrease reflects the higher investment spending of $12 million, a lower working capital decline of $23 million compared to 2000 and a decrease in cash flow provided from operations of $9 million. This decrease includes the recognition of estimated payments in 2002 with respect to Suncor's employee long-term compensation programs. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 REFINED PRODUCT SALES VOLUMES (thousands of cubic metres) 5 182 5 037 5 080 5 360 5 419 Total sales volumes increased by more than 1% over 2000, reflecting higher commercial/industrial sales volume and continued volume growth in the retail gasoline business. - -------------------------------------------------------------------------------- ANCILLARY INCOME Income earned from non-fuel products and services such as car washes, sale of fast foods and confectionery items. Working capital decreased by $17 million in 2001, compared with a reduction of $40 million in 2000, contributing $23 million to the net cash surplus decline. Key contributing factors were higher ending inventory and lower product prices impacting payables. Investing activities totalled $71 million in 2001, including $9 million for the planned maintenance shutdown at the Sarnia refinery, compared with $59 million in 2000. O U T L O O K Sunoco will continue to focus on improving gross profit of refining assets, enhancing its retail customer offerings, creating long-term growth opportunities and focusing on sustainable development. IMPROVE GROSS PROFIT OF REFINING ASSETS Sunoco continues to pursue its goal to position the Sarnia refinery in the top one-third of North American refineries of similar size and complexity by the end of 2002. To achieve this, Sunoco will continue to focus on increasing the operational flexibility of the Sarnia refinery to run different feedstocks, improving energy cost management and optimizing existing assets to improve reliability and flexibility. To reduce exposure to energy cost increases, an energy supply agreement was signed with TransAlta Energy Corporation (TransAlta) in 2001. Under the contract, the TransAlta Sarnia Regional Cogeneration Project will provide a portion of its steam supply to the Sarnia refinery at a competitive cost, eliminating the need for Sunoco to build boilers for steam generation. According to TransAlta, the new facility is expected to commence operation in late 2002. [GRAPHIC DESCRIPTION] 1997 1998 1999 2000 2001 MARGIN (Cdn cents per litre) Sunoco-branded Retail Gasoline Margin 6.8 7.0 7.4 6.6 6.6 Refining Margin 4.6 4.1 4.0 5.9 5.7 Refining margins declined from last year due mainly to the higher industry inventory levels and lower demand in North America. Sunoco retail gasoline margins remained unchanged from last year. 42 SUNCOR ENERGY INC. ENHANCE RETAIL CUSTOMER OFFERINGS Sunoco plans to implement initiatives to improve its retail customer offerings by expanding premium food and beverage service. Sunoco also continues to expand its premium fuel products to retail customers. Marketing initiatives are in place to increase sales of premium fuel products such as Ultra 94 gasoline and Gold Diesel. CREATE LONG-TERM GROWTH OPPORTUNITIES Sunoco continues to evaluate strategic opportunities associated with the industry's need to reformulate fuels to comply with new sulphur regulations on gasoline and diesel. Integration enhancement with Oil Sands and the economic attractiveness of processing sour streams continue to be a strategic focus. To capture a greater share of long-term value from increasing Oil Sands production, Sunoco will continue to assess new marketing and refining investment opportunities to further integrate Suncor's upstream and downstream businesses. Sunoco completed a strategic assessment in 2001 of its retail natural gas marketing business and is exploring possible disposition, joint venture or other transactions. FOCUS ON SUSTAINABLE DEVELOPMENT Sunoco completed a detailed emission reduction plan in 2001. The plan targets to reduce emissions of carbon dioxide, sulphur dioxide, nitrogen oxide and volatile organic compounds at the Sarnia refinery by 25% from the 1995 levels by 2005. While targeting improved margins and market growth, Sunoco also continues to focus on environmental issues facing Ontario and Canada and developing more environmentally responsible products. For example, to reduce emissions of carbon monoxide and greenhouse gas, Sunoco's retail network introduced ethanol-enhanced gasoline in 1997, which is now blended in all Sunoco gasoline and marketed through the Sunoco, UPI and Pioneer retail networks. Sunoco will continue to enforce management control programs to improve health and safety performance. RISK/SUCCESS FACTORS AFFECTING PERFORMANCE While Suncor's downstream business achieved higher operational earnings in 2001, financial performance in the second half of the year was negatively affected by margin and crude oil price volatility, lower demand for energy products and overall market competitiveness. Management expects fluctuation in demand for refined products, margin and price volatility and market competitiveness will continue to impact the business environment. The Canadian refining industry faces significant capital spending to construct sulphur removal facilities. The spending is required to comply with legislation limiting sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004 and a maximum of 30 ppm by 2005. In 2001, Sunoco finalized an investment plan to meet the sulphur content limits. Capital spending [GRAPHIC DESCRIPTION] BRIDGE 2000 2001 ANALYSIS OF NET EARNINGS (Cdn$ millions) Total 81 Fuel Margin (2) Fuel Volume 10 Retail Natural Gas Margin 10 Ancillary Income 4 Expenses (20) Earnings Before the Following 83 Tax Adjustment* (3) Total 80 Improvement in fuel volume, natural gas margin and ancillary income helped offset increased expenses and lower margins. Tax adjustments related to opening future income tax balances were $3 million lower than in 2000. * Provincial income tax rate adjustment on opening future tax balances. [GRAPHIC DESCRIPTION] BRIDGE 2000 2001 ANALYSIS OF NET CASH SURPLUS (Cdn$ millions) Total 155 Operations (9) Working Capital (23) Investing Activities (12) Total 111 Net cash surplus declined $44 million to $111 million in 2001 due to a combination of higher capital spending and lower reduction in working capital driven by higher inventory and lower accounts payable. 2001 ANNUAL REPORT 43 to achieve compliance is expected to be approximately $40 million and will involve the addition of a new desulphurization unit. Construction is expected to be completed in 2003. In 2001 Sunoco's sulphur level in gasoline averaged about 180 ppm, compared with the 2000 Ontario industry average of 450 ppm. Environment Canada is expected to finalize new on-road diesel sulphur regulations by mid-2002, with an implementation date of mid-2006. Regulations reducing sulphur in off-road diesel and light fuel oil are also expected. Sunoco continues to examine strategic options to comply with the pending regulations. Actual capital spending required to meet the new standard is subject to the development of such regulations and strategic assessment. Capital spending could be significant, but is not expected to place the company at a competitive disadvantage. These factors and estimates are subject to certain of the risks, assumptions and uncertainties discussed below under "Forward-looking Statement" and their achievement cannot be assured. Also refer to Risk/Success Factors Affecting Performance on page 27. - -------------------------------------------------------------------------------- FORWARD-LOOKING STATEMENT This Management's Discussion and Analysis contains certain forward-looking statements that are based on Suncor's current expectations, estimates, projections and assumptions and were made by the company in light of its experience and its perception of historical trends. All statements that address expectations or projections about the future, including statements about Suncor's strategy for growth, expected and future expenditures, commodity prices, costs, schedules and production volumes, operating and financial results, are forward-looking statements. Some of the forward-looking statements may be identified by words like `expects,' `anticipates,' `plans,' `intends,' `believes,' `projects,' `indicates,' `could,' `vision,' `goal,' `target,' `objective' and similar expressions. These statements are not guarantees of future performance and involve a number of risks, uncertainties and assumptions. Suncor's business is subject to risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements as a result of known and unknown risks, uncertainties and other factors. The risks, uncertainties and other factors that could influence actual results include: changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; fluctuations in commodity prices; fluctuations in currency exchange rates; Suncor's ability to respond to changing markets; the ability of Suncor to receive timely regulatory approvals; the successful implementation of its growth projects including the Firebag In-situ Oil Sands Project and Project Voyageur; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development projects; Suncor's ability to comply with current and future environmental laws; the accuracy of Suncor's production estimates and production levels and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venturers; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; actions by governmental authorities including increasing taxes, government fees, changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. Many of these risk factors are discussed in further detail throughout this Management's Discussion and Analysis and in the company's Annual Information Form on file with the Alberta Securities Commission and certain other securities regulatory authorities. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company. The tables and charts in this document form an integral part of Management's Discussion and Analysis and should be referred to when reading the narrative. References to Suncor or the company include Suncor Energy Inc. and its subsidiaries and investment in joint ventures, unless otherwise stated. 44 SUNCOR ENERGY INC. EX-4 6 a2075015zex-4.txt EXHIBIT 4 QUARTERLY SUMMARY (unaudited)
FINANCIAL DATA TOTAL Total Total FOR THE QUARTER ENDED YEAR For the Quarter Ended Year For the Quarter Ended Year MAR JUNE SEPT DEC Mar June Sept Dec Mar June Sept Dec ($ millions except 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2001 2001 2001 2001 2001 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 REVENUES 1 001 1 098 1 013 883 3 995 779 820 862 927 3 388 469 564 639 715 2 387 - ----------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS (LOSS) Oil Sands 69 108 69 37 283 90 81 76 68 315 17 34 43 73 167 Natural Gas 53 39 13 12 117 8 16 43 31 98 3 13 20 5 41 Sunoco 23 45 12 -- 80 19 20 19 23 81 5 3 12 7 27 Corporate and eliminations (20) (28) (21) (23) (92) (12) (6) (88) (11) (117) (14) (17) (5) (13) (49) - ----------------------------------------------------------------------------------------------------------------------------------- 125 164 73 26 388 105 111 50 111 377 11 33 70 72 186 =================================================================================================================================== PER COMMON SHARE - net earnings attributable to common shareholders - basic 0.53 0.71 0.30 0.09 1.63 0.45 0.47 0.19 0.47 1.58 0.04 0.12 0.29 0.29 0.74 - diluted 0.52 0.70 0.30 0.09 1.61 0.44 0.46 0.20 0.47 1.57 0.04 0.12 0.29 0.28 0.73 - ----------------------------------------------------------------------------------------------------------------------------------- - cash dividends 0.085 0.085 0.085 0.085 0.34 0.085 0.085 0.085 0.085 00.34 0.085 0.085 0.085 0.085 0.34 =================================================================================================================================== CASH FLOW PROVIDED FROM (USED IN) OPERATIONS Oil Sands 140 117 139 90 486 199 181 156 119 655 53 90 104 158 405 Natural Gas 127 76 42 35 280 48 42 64 84 238 42 43 39 48 172 Sunoco 50 67 30 18 165 46 38 49 41 174 23 17 37 26 103 Corporate and eliminations (42) (14) (34) (10) (100) (24) (17) (40) (28) (109) (25) (21) (33) (10) (89) - ----------------------------------------------------------------------------------------------------------------------------------- 275 246 177 133 831 269 244 229 216 958 93 129 147 222 591 ===================================================================================================================================
OPERATING DATA TOTAL Total Total FOR THE QUARTER ENDED YEAR For the Quarter Ended Year For the Quarter Ended Year MAR JUNE SEPT DEC Mar June Sept Dec Mar June Sept Dec ($ millions except 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2001 2001 2001 2001 2001 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 OIL SANDS PRODUCTION (a) 113.4 109.7 116.5 153.0 123.2 114.8 116.7 114.2 110.0 113.9 95.5 112.0 101.5 113.2 105.6 SALES (a) - - light sweet crude oil 53.0 55.0 54.2 62.4 56.2 67.7 64.3 61.4 64.0 64.3 54.6 41.3 52.1 62.8 52.7 - - diesel 13.5 15.2 15.0 15.3 14.8 8.7 8.6 8.9 11.0 9.3 7.9 6.8 8.4 9.5 8.2 - - light sour crude oil 31.4 31.5 40.6 64.3 42.0 39.1 41.7 35.6 27.5 35.8 27.3 47.9 40.6 35.1 37.5 - - bitumen 8.6 13.0 8.0 4.3 8.5 2.4 3.5 7.0 11.0 6.2 1.5 6.9 6.9 -- 3.8 - ------------------------------------------------------------------------------------------------------------------------------------ 106.5 114.7 117.8 146.3 121.5 117.9 118.1 112.9 113.5 115.6 91.3 102.9 108.0 107.4 102.2 - ------------------------------------------------------------------------------------------------------------------------------------ AVERAGE SALES PRICE (b) - - light sweet crude oil 36.09 36.05 35.20 30.22 34.17 34.35 33.54 36.21 37.22 35.31 20.55 24.47 27.23 30.81 26.06 - - other (diesel, light sour crude oil and 25.66 27.12 28.21 20.12 24.86 28.46 28.22 27.84 23.71 27.09 19.18 19.60 21.45 25.91 21.48 bitumen) - - total 30.84 31.40 31.43 24.43 29.17 31.84 31.12 32.39 31.33 31.67 20.00 21.57 24.24 28.77 23.84 - - total* 38.17 38.35 37.37 25.65 34.21 39.19 39.40 43.41 43.27 41.29 18.52 22.29 27.56 33.72 25.89 Cash operating costs (1)(c) 15.40 17.00 18.25 17.45 17.00 11.10 12.20 14.50 16.40 13.55 12.55 10.90 12.35 11.15 11.70 Total operating costs (2)(c) 18.60 19.65 20.95 19.40 19.60 15.50 16.60 18.55 19.50 17.25 15.60 14.30 15.30 15.10 15.05 ====================================================================================================================================
OPERATING DATA (CONTINUED) TOTAL Total Total FOR THE QUARTER ENDED YEAR For the Quarter Ended Year For the Quarter Ended Year MAR JUNE SEPT DEC Mar June Sept Dec Mar June Sept Dec ($ millions except 31 30 30 31 31 30 30 31 31 30 30 31 per share amounts) 2001 2001 2001 2001 2001 2000 2000 2000 2000 2000 1999 1999 1999 1999 1999 NATURAL GAS GROSS PRODUCTION** Conventional - natural gas (d) 177 177 176 180 177 222 195 200 183 200 229 225 231 219 226 - natural gas liquids (a) 2.3 2.3 2.4 2.4 2.4 3.5 3.1 2.8 2.5 3.0 4.7 4.1 4.1 4.0 4.2 - crude oil (a)*** 1.7 1.5 1.5 1.3 1.5 8.1 3.5 3.6 1.6 4.2 10.8 9.7 8.4 7.9 9.2 - total (e) 33.5 33.3 33.2 33.7 33.4 48.6 39.1 39.7 34.6 40.5 53.7 51.3 51.0 48.4 51.1 AVERAGE SALES PRICE - natural gas (f) 10.73 6.78 3.90 3.10 6.09 2.96 3.70 4.63 8.02 4.72 2.18 2.15 2.48 2.96 2.44 - natural gas (f)* 10.81 6.82 3.90 3.09 6.12 2.97 3.70 4.62 8.05 4.73 2.10 2.17 2.58 3.11 2.48 - natural gas liquids (b) 45.07 39.62 30.26 23.47 34.38 33.16 32.80 39.56 43.00 36.66 11.88 16.70 22.81 27.12 19.32 - crude oil - conventional (b) 37.35 36.75 33.17 27.17 33.92 26.30 30.04 33.09 36.01 29.50 18.48 20.48 20.55 25.21 20.94 - crude oil - conventional (b)* 42.12 42.30 37.86 28.60 38.14 38.23 38.65 42.31 44.35 39.80 16.28 21.89 28.01 32.72 24.01 SUNOCO Refined product sales (g)**** 14.9 15.3 15.1 14.0 14.8 14.3 15.1 14.0 15.2 14.6 13.1 14.1 13.9 14.2 13.8 Natural gas sales (d) 92 102 95 92 95 84 78 74 95 83 93 86 87 90 89 Margins - refining (3) (h) 6.2 8.1 4.3 3.7 5.7 5.4 6.3 6.1 5.8 5.9 3.4 3.3 4.8 4.3 4.0 - retail (4) (h) 6.1 7.6 5.9 6.9 6.6 6.8 6.4 6.4 7.0 6.6 7.9 7.6 6.9 7.2 7.4 Utilization of refining capacity (%) 88 98 99 83 92 102 99 96 95 98 97 93 100 92 95 ====================================================================================================================================
* Excludes the impact of hedging activities. ** Currently all Natural Gas production is located in the Western Canada Sedimentary Basin. *** Before deducting 2001 Alberta Crown royalty of 0.2 thousand barrels per day (2000 - 0.5 thousand barrels per day; 1999 - 0.9 thousand barrels per day). **** Excludes sales through joint venture interests. Definitions (1) Cash operating costs - operating, selling and general expenses, taxes other than income taxes, and overburden cash expenditures for the period. (2) Total operating costs - cash and non-cash operating costs (total Oil Sands expenses less purchases of crude oil and products and royalties in Schedules of Segmented Data on page 52 and 53). (3) Refining margin - average wholesale unit price from all products minus average unit cost of crude oil. (4) Retail margin - average street price of Sunoco-branded retail gasoline minus refining gasoline price. (a) thousands of barrels per day (d) millions of cubic feet per day (g) thousands of cubic metres per day (b) dollars per barrel (e) BOE (6:1 basis) per day (h) cents per litre (c) dollars per barrel sold (f) dollars per thousand cubic feet rounded to the nearest $0.05
Metric conversion Crude oil, refined products, etc. 1m(3) (cubic metre) = approx. 6.29 barrels Natural gas 1m(3) (cubic metre) = approx. 35.49 cubic feet
EX-5 7 a2075015zex-5.txt EXHIBIT 5 [PRICEWATERHOUSECOOPERS LOGO] PRICEWATERHOUSECOOPERS LLP CHARTERED ACCOUNTANTS 425 1st Street SW Suite 1200 Calgary Alberta Canada T2P 3V7 Telephone +1 (403) 509 7500 Facsimile +1 (403) 781 1825 REPORT OF INDEPENDENT ACCOUNTANTS ON THE RECONCILIATION TO US GAAP TO THE BOARD OF DIRECTORS OF SUNCOR ENERGY INC. Our audits of the consolidated financial statements referred to in our report dated January 16, 2002 appearing in the Annual Report to Shareholders of Suncor Energy Inc., which report and financial statements are incorporated by reference into this Form 40-F also included audits of the Reconciliation to US GAAP presented on pages 56 to 64 of this form 40-F. In our opinion, this Reconciliation to US GAAP is presented fairly, in all material respects, when read in conjunction with the related consolidated financial statements. CHARTERED ACCOUNTANTS CALGARY, ALBERTA JANUARY 16, 2002 CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS We hereby consent to the incorporation by reference in this Annual Report on Form 40-F of Suncor Energy Inc. for the year ended December 31, 2001 of our reports dated January 16, 2002 relating to the consolidated financial statements for the three years ended December 31, 2001 and relating to the Reconciliation to US GAAP for the three years ended December 31, 2001 (as set out on page 56 to 64 of the Form 40-F). We also hereby consent to the incorporation by reference in the Registration Statement on Form F-10 (file No. 333-14242) of Suncor Energy Inc. of our reports dated January 16, 2002 relating to the consolidated financial statements for the three years ended December 31, 2001 and relating to the 2001 Reconciliation to US GAAP for the three years ended December 31, 2001 (as set out on pages 56 to 64 of the Form 40-F) which are incorporated by reference and appears, respectively, in this Form 40-F. CHARTERED ACCOUNTANTS CALGARY, ALBERTA MARCH 28, 2002 EX-6 8 a2075015zex-6.txt EXHIBIT 6 [LOGO] GILBERT LAUSTSEN JUNG ASSOCIATES LTD. Petroleum Consultants 4100, 400 - 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2 (403) 266-9500 Fax (403) 262-1855 LETTER OF CONSENT TO: Suncor Energy Inc. The Securities and Exchange Commission The Securities Regulatory Authorities of each Province of Canada RE: SUNCOR ENERGY INC. We refer to the following reports prepared by Gilbert Laustsen Jung Associates Ltd.: - - the letter reports dated January 16, 2002, as to the synthetic crude oil reserves effective December 31, 2001 associated with the Suncor Energy Inc. oil sands mining operations located near Fort McMurray, Alberta; - - the Reserve Determination and Evaluation of the Canadian Oil and Gas Properties of Suncor Energy Inc. Natural Gas effective December 31, 2001, dated January 28, 2002; - - the Suncor Energy Inc. Natural Gas Constant Price Analysis effective December 31, 2001, dated January 29, 2002; - - the letter report dated January 22, 2002, as to the Firebag SAGD Project Approval Area Probable Nonproducing Reserves and Economic Analysis, effective December 31, 2001. We hereby consent to the use of our name, reference to and excerpts from the said reports by Suncor Energy Inc. in its Annual Information Form for the 2001 fiscal year (AIF), and to the incorporation by reference of the AIF in the annual report of Suncor Energy Inc. on Form 40-F and the registration statement on Form F-10 No. 333-14242. We have read the AIF and have no reason to believe that there are any misrepresentations in the information contained in it that is derived from our Reports or that are within our knowledge as a result of the services which we performed in connection with the preparation of the Reports. Yours very truly, GILBERT LAUSTSEN JUNG ASSOCIATES LTD. ORIGINALLY SIGNED BY Wayne W. Chow, P. Eng. Vice-President Calgary, Alberta Date: March 12, 2002 -----END PRIVACY-ENHANCED MESSAGE-----