EX-1 2 a2042188zex-1.txt EXHIBIT 1 EXHIBIT 1 SUNCOR ENERGY INC. 2000 RECONCILIATION OF RESULTS FROM CANADIAN GAAP TO U.S. GAAP (ALL FIGURES ARE IN CANADIAN DOLLARS) CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES The consolidated financial statements of Suncor Energy Inc. have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The adjustments under U.S. GAAP result in changes to the Consolidated Statements of Earnings and Consolidated Balance Sheets of the company as follows:
------------------------------------------------------------------------------------------------------------------------------- 2000 1999 1998 ------------------------------------------------------------------------------------------------------------------------------- (Canadian $ millions) CDN US CDN US CDN US ------------------------------------------------------------------------------------------------------------------------------- REVENUES Sales & other operating revenues (1) 3,385 3,481 2,383 2,448 2,068 2,107 Interest 3 3 4 4 2 2 ------------------------------------------------------------------------------------------------------------------------------- 3,388 3,484 2,387 2,452 2,070 2,109 ------------------------------------------------------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products 807 807 519 519 366 366 Operating, selling and general (1) (2) (3) 918 1,036 774 791 698 785 Exploration 53 53 40 40 40 40 Royalties 199 199 99 99 78 78 Taxes other than income taxes 361 361 334 334 325 325 Depreciation, depletion & amortization (4) 365 372 318 318 264 264 Gain on disposal of assets (148) (148) (34) (34) (6) (6) Write down of oil shale assets (5) 125 244 - - - - Restructuring 65 65 - - - - Start-up expenses - Project Millennium (6) 15 14 - 1 - - Start-up expenses - Other (6) - (13) - 31 - - Interest (4) 8 40 26 59 24 24 ------------------------------------------------------------------------------------------------------------------------------- 2,768 3,030 2,076 2,158 1,789 1,876 ------------------------------------------------------------------------------------------------------------------------------- EARNINGS BEFORE INCOME TAXES 620 454 311 294 281 233 ------------------------------------------------------------------------------------------------------------------------------- PROVISION FOR INCOME TAXES Current Income taxes on earnings 45 45 29 29 (3) (3) Income tax refund - - - - (16) (16) ------------------------------------------------------------------------------------------------------------------------------- 45 45 45 29 (19) (19) ------------------------------------------------------------------------------------------------------------------------------- Future Income taxes on earnings (2) (4) (5) (6) (7) 198 138 96 87 117 98 Income tax refund - - - - 5 5 ------------------------------------------------------------------------------------------------------------------------------- 198 138 96 87 122 103 ------------------------------------------------------------------------------------------------------------------------------- 243 183 125 116 103 84 ------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS 377 271 186 178 178 149 Dividends on preferred securities (4) (26) - (22) - - - ------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS 351 271 164 178 178 149 Other comprehensive income, net of tax Minimum pension liability (8) N/A (2) N/A 6 N/A (6) ------------------------------------------------------------------------------------------------------------------------------- COMPREHENSIVE INCOME N/A 269 N/A 184 N/A 143 ------------------------------------------------------------------------------------------------------------------------------- PER COMMON SHARE NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS Basic 1.58 1.22 0.74 0.81 0.81 0.68 Diluted 1.57 1.21 0.73 0.80 0.80 0.67 -------------------------------------------------------------------------------------------------------------------------------
* Per share calculations, for both current and prior years, reflect a two-for-one split of the company' common shares during 1998 and 2000. 2
AS AT as at DECEMBER 31, 2000 December 31, 1999 (CANADIAN $ MILLIONS) (Canadian $ millions) AS U.S. As U.S. REPORTED GAAP reported GAAP ---------- ---------- ---------- ---------- Current assets (8) 665 666 457 457 Capital assets, net (4) (5) (6) 5,883 5,768 4,528 4,503 Deferred charges and other (4) 166 173 191 205 Future income taxes (4) (6) (7) (8) 119 125 - - ---------- ---------- ---------- ---------- Total assets 6,833 6,732 5,176 5,165 ========== ========== ========== ========== Current liabilities 837 837 710 710 Long-term borrowings (4) 2,192 2,716 1,306 1,830 Accrued liabilities and other (3) (8) 252 277 236 236 Future income taxes (5) (7) 1,080 1,042 816 736 Equity: Share capital and retained earnings (4) 2,472 1,862 2,108 1,653 Accumulated other comprehensive Income (8) N/A (2) N/A - ---------- ---------- ---------- ---------- 2,472 1,860 2,108 1,653 ========== ========== ========== ========== Total liabilities and shareholders' equity 6,833 6,732 5,176 5,165 ========== ========== ========== ==========
(1) Under U.S. GAAP (EITF 00 - 10, "Accounting for Shipping and Handling Fees and Costs"), amounts billed to customers for shipping and handling costs should be classified as revenues, and shipping and handling costs incurred that relate to amounts billed to customers should be classified as expenses in the earnings statement. The company's accounting policy is to classify shipping and handling costs incurred that relate to amounts billed to customers as follows: o As "Operating, selling and general" for downstream refining and marketing operations; and o Deducted from "Sales and other operating revenues" for upstream operations. The company's accounting policy is acceptable under Canadian GAAP, which does not specifically address accounting for shipping and handling costs. The impact of EITF 00 - 10, which is one of reclassification only and does not affect net earnings, is to increase 2000 "Sales and other operating revenues" and "Operating, selling and general" expenses by $96 million (1999 - $65 million; 1998 - $39 million). 3 (2) The company is a party to certain off-balance-sheet derivative financial instruments, such as crude oil, natural gas and foreign currency swap contracts, in respect of future firmly committed and anticipated sales transactions. Under Canadian GAAP, foreign currency swap contracts qualify, and are accounted for, as hedges of these future transactions. Under U.S. GAAP, foreign currency swap contracts used to hedge foreign currency exposure to anticipated, but not firmly committed, transactions cannot be accounted for as hedges under SFAS No. 52, "Foreign Currency Translation". Accordingly, for reporting under U.S. GAAP, gains or losses resulting from changes in the market value of foreign currency swap contracts related to these anticipated transactions are recognized in earnings when those changes in market value occur. At December 31, 2000, there were no foreign currency swap contracts outstanding to hedge foreign currency exposure to anticipated transactions and, therefore, no impact on net earnings. As at December 31, 1999, the market value of such contracts was nil therefore, the loss recognized in 1998 was reversed. This 1998 loss reversal resulted in an increase in 1999 net earnings of $29 million after future income taxes of $19 million (1998 - net earnings decreased by $29 million after future income tax recoveries of $19 million). (3) Under U.S. GAAP (APB 25, "Accounting for Stock Issued to Employees"), compensation expense is also recorded, over the same vesting period, for the portion of these awards payable in common shares. The impact of this GAAP difference is to decrease 2000 net earnings by $22 million (1999 and 1998 - $ nil). Since the common shares awarded under these plans are to be issued from treasury, the income tax impact on the company is nil. STOCK-BASED COMPENSATION The company applies APB Opinion 25 in accounting for common share options granted to non-employee directors and certain executives. Accordingly, no compensation cost has been recognized in the consolidated statements of earnings. Had compensation cost been determined on the basis of fair values in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation", 2000 net earnings would have been lower by $7 million ($0.03 per common share), 1999 net earnings would have been lower by $5 million ($0.02 per common share) and 1998 net earnings would have been lower by $3 million ($0.03 per common share). (4) Under Canadian GAAP, the preferred securities issued in 1999 are classified as share capital in the consolidated balance sheets and the interest distributions thereon, net of income taxes, are accounted for as dividends in the consolidated statements of changes in shareholders' equity. Under US GAAP, the preferred securities are classified as long-term borrowings in the consolidated balance sheets and the interest distributions thereon and the related income tax impact are accounted for in the consolidated statements of earnings. Under Canadian GAAP, issue costs of the preferred securities, net of the related income tax credits, are charged against share capital. Under US GAAP, issue costs are deferred on the consolidated balance sheets and amortized to earnings over the term of the related long-term borrowings. 4 This difference in classification decreased 2000 net earnings by $31 million after income tax recoveries of $23 million (1999 net earnings decreased $20 million after income tax recoveries of $17 million). However, the interest distributions on the preferred securities above are eligible for interest capitalization under U.S. GAAP, resulting in an increase in 2000 net earnings of $9 million after future income taxes of $6 million (1999 net earnings increased $2 million after future income taxes of $2 million). These preferred securities, which are publicly traded, had a fair value, based on quoted market prices, of $544 million at December 31, 2000 (1999 - $492 million). Under Canadian GAAP, the 2000 interest distributions of $47 million (1999 - $37 million) on the preferred securities are classified as financing activities in the consolidated statements of cash flows. Under U.S. GAAP (SFAS No.95, "Statement of Cash Flows"), the interest distributions and the amortization of issue costs of $7 million are classified as operating activities. (5) In 2000, the company recorded an impairment write down of the carrying value of the Stuart oil shale project to its net recoverable amount, which under Canadian GAAP is its estimated future cash flow from use together with its residual value, calculated on an undiscounted basis. Under U.S. GAAP (SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"), an impairment loss is measured based on the fair value of the asset, which in the case of the oil shale project is its estimated net cash flows, but calculated on a discounted basis. The impact of this GAAP difference is to decrease 2000 net earnings by $64 million, after income tax recoveries of $55 million. (6) Under U.S. GAAP (AICPA Statement of Position 98-5, "Reporting the Costs of Start-Up Activities"), all costs relating to start-up activities are expensed as incurred. Under Canadian GAAP, certain costs relating to the company's start-up activities are initially capitalized and then amortized over the estimated useful lives of the related assets. Under Canadian GAAP in 2000: o Certain costs associated with the Stuart oil shale project that were previously capitalized were written down. Under U.S. GAAP, these start-up costs were expensed in 1999. These differences increased 2000 net earnings by $8 million after related income taxes of $6 million (1999 decreased net earnings by $12 million after related income tax credits of $8 million). (7) In December 2000, the Canadian Federal Department of Finance released draft legislation that merged federal budget proposals announced earlier in the year. Under Canadian GAAP, the budget proposals are considered substantially enacted. Accordingly, future income tax assets and liabilities have been measured taking into account the reduction in tax rates presented in the draft legislation. Under US GAAP, in accordance with SFAS 109 "Accounting for Income Taxes", changes in tax rates and tax laws on temporary differences are only after they have been signed into law. 5 The impact of this GAAP difference was to decrease 2000 net earnings by $6 million (1999 and 1998 - nil). At December 31, 2000, future income taxes, under Canadian and U.S. GAAP, are comprised of the following:
AS REPORTED U.S. GAAP ($ millions) CURRENT NON-CURRENT CURRENT NON-CURRENT ------------ ------------ ------------ ------------ Future income tax assets: Employee future benefits 2 39 2 41 Reclamation and environmental remediation costs 9 23 9 24 Royalties - 43 - 43 Employee incentive plans - 4 - 10 Inventories 20 - 21 - Other 14 10 14 - ------------ ------------ ------------ ------------ 45 119 46 125 ============ ============ ============ ============ Future income tax liabilities Depreciation - 1,038 - 992 Overburden removal costs - 23 - 23 Maintenance shutdown costs - 12 - 12 Other 9 7 9 15 ============ ============ ============ ============ 9 1,080 9 1,042 ============ ============ ============ ============
(8) Under U.S. GAAP (SFAS No.87, "Employers' Accounting for Pensions"), recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is greater than accrued pension costs otherwise recorded. No such adjustment is required under Canadian GAAP. Recording the additional minimum liability affects the consolidated balance sheet only and has no impact on net earnings or cash flows. An intangible asset equal to the amount of any unamortized liabilities arising from plan amendments is recognized. Any excess of the additional minimum liability over the amount recognized as an intangible asset is recorded as a separate component of equity (net of any related income tax recoveries), and is included as a component of comprehensive income under SFAS No. 130, "Reporting Comprehensive Income". At December 31, 2000, an additional minimum pension liability of $3 million and other comprehensive income of $2 million, net of income tax recoveries of $1 million, was recognized. At December 31, 2000, unamortized liabilities arising from plan amendments were nil. At December 31, 1999, the accumulated benefit obligation did not exceed the fair value of plan assets and accrued pension costs otherwise recorded. Accordingly, as at December 31, 1999 the additional minimum pension liability and related intangible asset recognized at 6 December 31, 1998 was adjusted to nil, and other comprehensive income of $6 million, net of income taxes of $4 million, was recognized. EMPLOYEE FUTURE BENEFITS Effective January 1, 2000, the company adopted new Canadian accounting recommendations with respect to accounting for the costs of employee future benefits. The new recommendations were applied in a manner that produced recognized and unrecognized amounts for all of its benefit plans the same as those determined by the application of U.S. GAAP (SFAS No. 87, "Employers Accounting for Pensions; SFAS No. 106, "Employers' Accounting for Post-Retirement Benefits Other than Pensions" and SFAS No. 112, "Accounting for Post-Employment Benefits"). For Canadian reporting, the new recommendations were adopted retroactively and financial statements of prior periods were restated to give effect to them. Accordingly, for U.S. reporting, comparative figures have also been restated to reflect the fact that GAAP differences previously reported no longer apply. RECENTLY ISSUED ACCOUNTING STANDARDS DERIVATIVE FINANCIAL INSTRUMENTS Effective January 1, 2001, the company will adopt SFAS 133 Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchase and sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income (OCI) and are recognized in the income statement when the hedged item is realized. Ineffective portions of changes in the fair value and the cash flow hedges are recognized in earnings, immediately. The adoption of SFAS 133 is expected to result in a decrease in OCI of $173 million, net of future income tax recoveries of $87 million and an increase in 2001 U.S. GAAP earnings of $47 million net of future income taxes of $28 million. Assets are expected to increase by $89 million and liabilities are expected to increase by $274 million as a result of recording all derivative instruments on the consolidated Balance Sheet at fair value. Implementation of this accounting standard will not affect the company's cash flow or liquidity. OIL AND GAS DATA The following data supplements oil and gas disclosure in the company's Annual Report, and is provided in accordance with the provision of the United States Financial Accounting Standards Board's Statement No. 69. This statement requires disclosure about conventional oil and gas activities only, and therefore the company's oil sands activities are excluded. 7 COSTS INCURRED
COSTS INCURRED FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Property acquisition costs Proved properties.............................................. 5 - - Unproved properties............................................ 10 48 24 Exploration costs................................................ 40 64 92 Development costs................................................ 69 70 123 --- --- --- 124 182 239 === === ===
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers.................................. 139 97 80 Transfers to other operations.................................... 183 153 167 ---- ---- ---- 322 250 247 ---- ---- ---- Expenses Production costs................................................. 47 63 64 Depreciation, depletion and amortization......................... 68 76 74 Exploration...................................................... 63 52 50 Gain on disposal of assets....................................... (147) (36) (4) Restructuring costs.............................................. 65 - - ---- ---- ---- Other related costs.............................................. 25 21 18 ---- ---- ---- 121 176 202 ---- ---- ---- Operating profit before income taxes............................... 201 74 45 Related income taxes............................................... (103) (33) (21) ---- ---- ---- Results of operations from Natural Gas............................. 98 41 24 ==== ==== ====
The information noted above does not totally agree to the segmented information on page 48 of the company's annual report due to different classification of revenues and expenses,
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers................................... 139 97 80 Transfers to other operations..................................... 183 153 167 ---- ---- ---- 322 250 247 ---- ---- ---- Expenses Production costs.................................................. 47 63 64 Depreciation, depletion and amortization.......................... 68 76 74 Exploration....................................................... 63 52 50 Gain on disposal of assets........................................ (147) (36) (4) Restructuring costs............................................... 65 - - ---- ---- ---- Other related costs............................................... 25 21 18 ---- ---- ---- 121 176 202 ---- ---- ---- Operating profit before income taxes................................ 201 74 45 Related income taxes................................................ (103) (33) (21) ---- ---- ---- Results of operations from Natural Gas.............................. 98 41 24 ==== ==== ====
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RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers.................................. 139 97 80 Transfers to other operations.................................... 183 153 167 ---- ---- ---- 322 250 247 ---- ---- ---- Expenses Production costs................................................. 47 63 64 Depreciation, depletion and amortization......................... 68 76 74 Exploration...................................................... 63 52 50 Gain on disposal of assets....................................... (147) (36) (4) Restructuring costs.............................................. 65 - - ---- ---- ---- Other related costs.............................................. 25 21 18 ---- ---- ---- 121 176 202 ---- ---- ---- Operating profit before income taxes............................... 201 74 45 Related income taxes............................................... (103) (33) (21) ---- ---- ---- Results of operations from Natural Gas............................. 98 41 24 ==== ==== ====
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES In computing the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes, assumptions other than those mandated by SFAS No. 69 could produce substantially different results. The Company cautions against viewing this information as a forecast of future economic conditions or revenues. Figures are based on year-end commodity prices. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. At December 31, 2000, no such contractual arrangements existed. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, the Company has also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and reclamation and environmental remediation costs. Deducting future income tax expenses then reduces the estimated pretax future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax cash flows relating to the Company's proved oil and gas reserves less the tax basis of the properties involved. At December 31, 2000, there were no legislated future tax rate changes. The future income tax expenses give effect to permanent differences and tax credits and allowances relating to the company's proved oil and gas reserves. The resultant future net cash flows are reduced to present value amounts by applying the SFAS No. 69 mandated 10% discount factor. The result is referred to as "Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes". 9
2000 1999 1998 ------ ------ ------ ($ MILLIONS) Future cash inflows..................................................... 8,176 3,272 3,382 Future production and development costs................................. (633) (1,053) (1,183) Other related future costs.............................................. (175) (133) (139) Future income tax expenses.............................................. (3,426) (789) (637) ------ ------ ------ Future net cash flows................................................... 3,942 1,297 1,423 Discount at 10%......................................................... (2,009) (548) (626) ------ ------ ------ Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes............................................................ 1,933 749 797 ====== ====== ======
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES
2000 1999 1998 ------ ------ ------ ($ MILLIONS) Balance, beginning of year.............................................. 749 797 678 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas net of related costs............... (275) (192) (187) Revisions to estimates of proved reserves: Prices............................................................. 3,886 458 69 Development costs.................................................. (3) (68) (75) Production costs................................................... 55 (25) (26) Quantities......................................................... (363) (175) (19) Other.............................................................. (237) (81) (6) Extensions, discoveries, and improved recovery less related costs..... 177 46 168 Development costs incurred during the period.......................... 69 70 123 Purchases of reserves in place........................................ 41 - - Sales of reserves in place............................................ (989) (130) (13) Accretion of discount................................................. 115 113 100 Income taxes.......................................................... (1,292) (64) (15) ------ ------ ------ Balance, end of year.................................................... 1,933 749 797 ====== ====== ======
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