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.