EX-1 3 a2075015zex-1.txt EXHIBIT 1 SUNCOR ENERGY INC. 2001 RECONCILIATION OF RESULTS FROM CANADIAN GAAP TO U.S. GAAP (ALL FIGURES ARE IN CANADIAN DOLLARS) CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES The consolidated financial statements of Suncor Energy Inc. have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The measurement adjustments under U.S. GAAP result in changes to the Consolidated Statements of Earnings and Consolidated Balance Sheets of the company as follows:
------------------------------------------------------------------------------------------------------------------------------- 2001 2000 1999 ------------------------------------------------------------------------------------------------------------------------------- ($ millions) CDN US CDN US CDN US ------------------------------------------------------------------------------------------------------------------------------- REVENUES Sales & other operating revenues (1) (8) 3,990 4,077 3,385 3,481 2,383 2,448 Interest 5 5 3 3 4 4 Other income (8) - 20 - - - - ------------------------------------------------------------------------------------------------------------------------------- 3,995 4,102 3,388 3,484 2,387 2,387 ------------------------------------------------------------------------------------------------------------------------------- EXPENSES Purchases of crude oil and products 1,391 1,391 807 807 519 519 Operating, selling and general (1) (2) (8) 1,010 1,148 918 1,036 774 791 Exploration 22 22 53 53 40 40 Royalties 134 134 199 199 99 99 Taxes other than income taxes 367 367 361 361 334 334 Depreciation, depletion & amortization (3) 360 365 365 372 318 318 Gain on disposal of assets (7) (7) (148) (148) (34) (34) Write down of oil shale assets (4) 48 (71) 125 244 - - Restructuring (2) (2) 65 65 - - Start-up expenses- Project Millennium 141 141 15 14 - 1 - Other (5) - (17) - (13) - 31 Interest (3) 18 62 8 40 26 59 ------------------------------------------------------------------------------------------------------------------------------- 3,482 3,533 2,768 3,030 2,076 2,158 ------------------------------------------------------------------------------------------------------------------------------- 513 569 620 454 311 294 EARNINGS BEFORE INCOME TAXES ------------------------------------------------------------------------------------------------------------------------------- PROVISION FOR (RECOVERY OF) INCOME TAXES Current (8) 4 (7) 45 45 29 29 Future (3) (4) (5) (6) (8) 121 157 198 138 96 87 ------------------------------------------------------------------------------------------------------------------------------- 125 150 243 183 125 116 ------------------------------------------------------------------------------------------------------------------------------- 388 419 377 271 186 178 NET EARNINGS Dividends on preferred securities (3) (26) - (26) - (22) - ------------------------------------------------------------------------------------------------------------------------------- NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS 362 419 351 271 164 178 PER COMMON SHARE NET EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS Basic 1.63 1.88 1.58 1.22 0.74 0.81 Diluted 1.61 1.86 1.57 1.21 0.73 0.80 ------------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME, NET OF TAX Minimum pension liability (7) N/A (28) N/A (2) N/A 6 Hedging activities (8) N/A 29 N/A - N/A - ------------------------------------------------------------------------------------------------------------------------------- OTHER COMPREHENSIVE INCOME N/A 1 N/A (2) N/A 6 -------------------------------------------------------------------------------------------------------------------------------
* Per share calculations, for both current and prior years, reflect a two-for-one split of the company' common shares during 2000.
AS AT as at DECEMBER 31, 2001 December 31, 2000 ($ MILLIONS) ($ millions) AS U.S. As U.S. REPORTED GAAP reported GAAP ------------ ------------ ------------ ------------ Current assets (8) 622 694 665 666 Capital assets, net (3) 7,141 7,174 5,883 5,768 Deferred charges and other (3) (7) 199 210 166 173 Future income taxes (3) (7) 132 159 119 125 ------------ ------------ ------------ ------------ Total assets 8,094 8,237 6,833 6,732 ============ ============ ============ ============ Current liabilities (8) 773 806 837 837 Long-term borrowings (3) 3,113 3,649 2,192 2,716 Accrued liabilities and other (2) (7) 251 336 252 277 Future income taxes (3) 1,180 1,220 1,080 1,042 Equity: Share capital and retained earnings (3) 2,777 2,225 2,472 1,862 Accumulated other comprehensive Income (7) (8) N/A 1 N/A (2) ------------ ------------ ------------ ------------ 2,777 2,226 2,472 1,860 ------------ ------------ ------------ ------------ Total liabilities and shareholders' equity 8,094 8,237 6,833 6,732 ============ ============ ============ ============
(1) Under U.S. GAAP (EITF 00 - 10, "Accounting for Shipping and Handling Fees and Costs"), amounts billed to customers for shipping and handling costs should be classified as revenues, and shipping and handling costs incurred that relate to amounts billed to customers should be classified as expenses in the earnings statement. The company's accounting policy is to classify shipping and handling costs incurred that relate to amounts billed to customers as follows: o As "Operating, selling and general" for downstream refining and marketing operations; and o Deducted from "Sales and other operating revenues" for upstream operations. The company's accounting policy is acceptable under Canadian GAAP, which does not specifically address accounting for shipping and handling costs. The impact of EITF 00 - 10, which is one of reclassification only and does not affect net earnings, is to increase 2001 "Sales and other operating revenues" and "Operating, selling and general" expenses by $95 million (2000 - $96 million; 1999 - $65 million). (2) Under Canadian GAAP, no compensation cost has been recognized in the consolidated statements of earnings for common share options granted to executives, certain employees and non-employee directors under the company's share option programs. Had compensation cost been determined on the basis of fair values in accordance with SFAS No. 123, "Accounting for Stock-Based Compensation", 2001 net earnings would have been lower by $9 million (2000 - $7 million; 1999 - $5 million) and 2001 earnings per share would have been lower by $0.04 (2000 - $0.03; 1999 - $0.02). Under U.S. GAAP (Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"), compensation expense is also recorded, over the same vesting period, for the portion of awards payable in common shares to employees under the company's long-term employee incentive plans. The impact of this GAAP difference is to decrease 2001 net earnings by $14 million (2000 - $22 million; 1999 - nil). Since the common shares awarded under these plans are to be issued from treasury, the income tax impact on the company is nil. (3) Under Canadian GAAP, the preferred securities issued in 1999 are classified as share capital in the consolidated balance sheets and the interest distributions thereon, net of income taxes, are accounted for as dividends in the consolidated statements of changes in shareholders' equity. Under US GAAP, the preferred securities are classified as long-term borrowings in the consolidated balance sheets and the interest distributions thereon and the related income tax impact are accounted for in the consolidated statements of earnings. Under US GAAP, the portion of the preferred securities that is denominated in US dollars, U.S. $163 million, is valued at the exchange rate in effect at the year end. Under Canadian GAAP, issue costs of the preferred securities, net of the related income tax credits, are charged against share capital. Under US GAAP, issue costs are deferred on the consolidated balance sheets and amortized to earnings over the term of the related long-term borrowings. This difference in classification decreased 2001 net earnings by $28 million after income tax recoveries of $23 million (2000 decreased net earnings by $31 million after income tax recoveries of $23 million; 1999 - decreased net earnings by $20 million after income tax recoveries of $17 million). However, the interest distributions on the preferred securities above are eligible for interest capitalization under U.S. GAAP, resulting in an increase in 2001 net earnings of $9 million after future income taxes of $5 million (2000 - increased net earnings by $9 million after future income taxes of $6 million; 1999 - increased net earnings by $2 million after future income taxes of $2 million). The net effect of all of the above differences decreased 2001 net earnings by $27 million (2000 - $22 million; 1999 - $18 million). These preferred securities, which are publicly traded, had a fair value, based on quoted market prices, of $575 million at December 31, 2001 (2000 - $544 million; 1999 - $492 million). Under Canadian GAAP, the 2001 interest distributions of $48 million (2000 - $47 million; 1999 - $37 million) on the preferred securities are classified as financing activities in the consolidated statements of cash flows. Under U.S. GAAP (SFAS No.95, "Statement of Cash Flows"), the interest distributions and the 2001 amortization of issue costs of $3 million (2000 - $7 million) are classified as operating activities. (4) Effective April 5, 2001, the company sold its interest in the Stuart oil shale project and, as a result, the company wrote off the carrying value of the interest. Under Canadian GAAP, the carrying value of the interest in the Stuart oil shale project is calculated as the estimated future cash flow from use together with its residual value, calculated on an undiscounted basis. Under U.S. GAAP (SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"), the carrying value of the interest in the Stuart oil shale project is calculated as the estimated net cash flows, but calculated on a discounted basis. As a result of this GAAP difference in the calculation of the carrying value of the interest in the Stuart oil shale project, the write down in 2000 and the subsequent write off in 2001 of the carrying value of the interest is different under US GAAP. The impact of this GAAP difference is to increase 2001 net earnings by $64 million, after income taxes of $55 million (2000 decrease net earnings by $64 million, after income tax recoveries of $55 million). (5) Under U.S. GAAP (AICPA Statement of Position 98-5, "Reporting the Costs of Start-Up Activities"), all costs relating to start-up activities are expensed as incurred. Under Canadian GAAP, certain costs relating to the company's start-up activities are initially capitalized and then amortized over the estimated useful lives of the related assets. Under Canadian GAAP, in 2001, the remaining costs associated with the Stuart oil shale project that were previously capitalized were written down. Under U.S. GAAP, these start-up costs were expensed in 1999. These differences increased 2001 net earnings by $10 million after related income taxes of $7 million (2000 - increased net earnings by $8 million after related income taxes of $6 million; 1999 - decreased net earnings by $12 million after related income tax credits of $8 million). (6) In December 2000, the Canadian Federal Department of Finance released draft legislation that merged federal budget proposals announced earlier in the year. The draft legislation was enacted into law in June, 2001. Under Canadian GAAP, the budget proposals were considered to be substantially enacted at December 31, 2000. Accordingly, future income tax assets and liabilities at December 31, 2000 were measured taking into account the reduction in tax rates presented in the draft legislation. Under US GAAP, in accordance with SFAS 109 "Accounting for Income Taxes", changes in tax rates and tax laws are considered only after they have been enacted into law. The impact of this GAAP difference was to increase 2001 net earnings by $6 million (2000 - decrease net earnings by $6 million; 1999 - nil). (7) Under U.S. GAAP (SFAS No.87, "Employers' Accounting for Pensions"), recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is greater than accrued pension costs otherwise recorded. No such adjustment is required under Canadian GAAP. Recording the additional minimum liability affects the consolidated balance sheet only and has no impact on net earnings or cash flows. An intangible asset equal to the amount of any unamortized liabilities arising from plan amendments is recognized. Any excess of the additional minimum liability over the amount recognized as an intangible asset is recorded as a separate component of equity (net of any related income tax recoveries), and is included as a component of comprehensive income under SFAS No. 130, "Reporting Comprehensive Income". At December 31, 2001, an additional minimum pension liability of $52 million (2000 - $3 million), an intangible asset of $12 million (2000 - nil) and other comprehensive income of $28 million (2000 - $2 million), net of income tax recoveries of $12 million (2000 - $1 million), was recognized under U.S. GAAP. The impact of this GAAP difference is to decrease 2001 other comprehensive income by $28 million (2000 - decrease of $2 million; 1999 - increase of $6 million). (8) Derivative Financial Instruments Effective January 1, 2001, the company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS 138, (the Standards), which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchase and sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the effective portions of the changes in the fair value of the derivative, and changes in the fair value of the hedged item attributable to the hedged risk, are recognized in the income statement. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are recorded in other comprehensive income (OCI) and are recognized in the income statement when the hedged item is recognized. Accordingly, ineffective portions of changes in the fair value of hedging instruments are recognized in earnings immediately. Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same earnings statement caption as the hedged item. Gains or losses from derivative instruments for which hedge accounting is not applied are reported in other income. In accordance with the transition provisions of the Standards, the company recorded the following after-tax cumulative adjustments on January 1, 2001: A decrease in OCI of $173 million, net of future income tax recoveries of $87 million and an increase in 2001 US GAAP earnings of $47 million net of future income taxes of $28 million. Assets increased by $89 million and liabilities increased by $274 million as a result of recording all derivative instruments on the consolidated Balance Sheet at fair value. Commodity Price Risk The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of market prices for its petroleum and natural gas products. The company manages its Canadian dollar crude price exposure by entering into US dollar WTI derivative transactions and in some instances combines US dollar WTI derivative transactions and Canadian/US foreign exchange derivative contracts. The company has hedged future cash flows subject to commodity price risk for up to four years. Interest Rate Risk The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest bearing debt. The company has interest rate derivatives outstanding for up to two years classified as cash flow hedges. During 1996, the company entered into a cross currency swap transaction to convert its 7.4% Debentures to a 6.2% fixed interest rate U.S. dollar obligation of approximately $91 million. Later in 1996, the company entered into another cross currency interest rate swap transaction to convert the U.S. $91 million obligation back to a fixed rate Canadian $125 million obligation. The net effect of the two swap transactions was to reduce the effective interest rate on the debentures from 7.3% (7.4% coupon rate) to 5.5%. The transactions did not qualify for hedge accounting. In 2001, the company monetized the two swap transactions and realized a gain of $5.7 million of which, $4.9 million was deferred for Canadian purposes. The entire gain was recognized in current period earnings for US purposes. Inventory Monetization In 1999, the company sold inventory and subsequently entered into a derivative contract with an option to repurchase the inventory at the end of five years. The company realized an economic benefit as a result of liquidating a portion of its inventory. The derivative did not qualify for hedge accounting because the company did not have purchase price risk associated with the repurchase of the inventory. This derivative does not represent a US GAAP difference as the company records this derivative at fair value for Canadian purposes. During the year, the company settled early a long-term contract that was designated as a hedge under Canadian GAAP. Under US GAAP, the long-term contract was designated as a normal purchase and sale. Accordingly, the payment of $29 million was deferred for Canadian purposes and for US purposes, was recognized in current period earnings. For Canadian GAAP, the $29 million will be recognized in income as the hedged item is settled. A reconciliation of changes in OCI attributable to derivatives and hedging activities is as follows:
------------------------------------------------------------------------------------------------------ OCI ---------------------------------------------------------------------- ------------------------------- (millions $) ------------------------------------------------------------------------------------------------------ Net derivative losses, net of $87 million future tax recoveries, arising from implementation of the Standards (173) ------------------------------------------------------------------------------------------------------ Current period net hedging gains arising from cash flow hedges, net of $50 million future tax expense 79 ------------------------------------------------------------------------------------------------------ Net hedging losses at beginning of the period reclassified to earnings during the period, net of $62 million future tax recoveries 123 ------------------------------------------------------------------------------------------------------ Total net hedging gain net of future tax of $13 million 29 ------------------------------------------------------------------------------------------------------
During the year, assets increased by $93 million and liabilities increased by $44 million as a result of recording all derivative instruments on the consolidated Balance Sheet at fair value. The loss associated with hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $25 million net of $12 million tax. The company estimates that $3 million of hedging losses net of future tax recoveries of $2 million will be reclassified from OCI to current period earnings within the next 12 months as a result of forecasted sales occurring. There were no derivative instruments designated as fair value hedges. Implementation of the standards did not affect the company's cash flows or liquidity. The Standards are complex and subject to a potentially wide range of interpretations in their application. The FASB continues to consider several issues, and the potential exists for additional issues to be brought under its review. Therefore, if subsequent FASB interpretations of the Standards are different than the company's initial application, it is possible that the impact of the company's application of the Standards, as described above, will be modified. RECENTLY ISSUED ACCOUNTING STANDARDS ASSET RETIREMENT OBLIGATIONS In August 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued. This statement changes the method and timing of accruing for costs arising from legal obligations associated with the retirement of tangible capital assets and the associated asset retirement costs. The company will evaluate the impact and timing of implementing SFAS 143, which must be adopted no later than January 1, 2003. IMPAIRMENT OF LONG-LIVED ASSETS In August 2001, SFAS No. 144, "Accounting for the Impairment and Disposal of Long-Lived Assets" was issued. SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" but retains its fundamental provisions for recognition and measurement of impairment of long-lived assets to be held and used, and measurement of long-lived assets to be disposed of by sale. SFAS 144 also supersedes the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" for segments of a business to be disposed of, but retains APB 30's requirement to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. The company will evaluate the impact of implementing SFAS 144, which must be adopted on January 1, 2002. HEDGING RELATIONSHIPS In 2001, the Accounting Standards Board of the CICA approved a new Accounting Guideline, "Hedging Relationships", which deals with the identification, documentation and effectiveness of hedging relationships for the purpose of applying hedge accounting. The Guideline is meant to codify certain best practices and, wherever possible, harmonize with certain requirements of U.S. GAAP, in particular SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 138. The company will evaluate the impact of implementing the new standard, which must be adopted no later than January 1, 2003. FOREIGN CURRENCY TRANSLATION In 2001, the Accounting Standards Board of the Canadian Institute of Chartered Accountants approved amendments to CICA Handbook Section 1650, Foreign Currency Translation. The amendments to Section 1650, applicable for the company in fiscal 2002 with retroactive application, eliminate the deferral and amortization method for unrealized translation gains and losses on non current monetary assets and liabilities and require the disclosure of exchange gains and losses included in net income. STOCK-BASED COMPENSATION In 2001, the Accounting Standards Board of the Canadian Institute of Chartered Accountants approved amendments to CICA Handbook Section 3870, Stock-Based Compensation and Other Stock-Based Payments. Under the amendments to Section 3870, stock-based payments to non-employees and direct awards of stock to employees and non-employees will be accounted for using a fair value method of accounting. The standard provides for the recognition of compensation expense based on fair values or a disclosure only basis of accounting. The standard is effective for years beginning on or after January 1, 2002. The company will apply this standard in fiscal 2002 and has not yet determined the impact. Implementation of the above noted accounting standards will not affect the company's cash flows or liquidity. OIL AND GAS DATA The following data supplements oil and gas disclosure in the company's Annual Report, and is provided in accordance with the provision of the United States Financial Accounting Standards Board's Statement No. 69. This statement requires disclosure about conventional oil and gas activities only, and therefore the company's oil sands activities are excluded. COSTS INCURRED
COSTS INCURRED FOR THE YEARS ENDED DECEMBER 31, ------------ 2001 2000 1999 ---- ---- ---- ($ MILLIONS) Property acquisition costs Proved properties.................................. - 5 - Unproved properties................................ 11 10 48 Exploration costs.................................... 35 40 64 Development costs.................................... 84 69 70 --- --- --- 130 124 182 === === ===
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, ------------ 2001 2000 1999 ---- ---- ---- ($ MILLIONS) Revenues Sales to unaffiliated customers................... 128 139 97 Transfers to other operations..................... 207 183 153 --- --- --- 335 322 250 --- --- --- Expenses Production costs.................................. 36 47 63 Depreciation, depletion and amortization.......... 61 68 76
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCTION FOR THE YEARS ENDED DECEMBER 31, ------------ 2001 2000 1999 ---- ---- ---- ($ MILLIONS) Exploration....................................... 31 63 52 Gain on disposal of assets........................ (8) (147) (36) Restructuring costs............................... (2) 65 - Other related costs............................... 21 25 21 --- --- --- 139 121 176 --- --- --- Operating profit before income taxes................. 196 201 74 Related income taxes................................. (79) (103) (33) ---- --- ---- Results of operations from Natural Gas................ 117 98 41 === === ===
The information noted above does not totally agree to the segmented information on page 51 of the company's annual report due to different classification of revenues and expenses, STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES In computing the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes, assumptions other than those mandated by SFAS No. 69 could produce substantially different results. The Company cautions against viewing this information as a forecast of future economic conditions or revenues, and does not consider it to represent the fair market value of gas properties. Figures are based on year-end commodity prices, and are as follows:
2001 2000 1999 Year end natural gas price assumptions (AECO - $/mcf) 3.55 13.52 2.90
Actual future net cash flows may differ from those estimated due to, but not limited to, the following: o Production rates could differ from those estimated both in terms of timing and amount; o Future prices and economic conditions will likely differ from those at yearend; o Future production and development costs will be determined by future events and may differ from those at year end; and o Estimated income taxes may differ in terms of amounts and timing due to the above factors as well as changes in enacted rates and the impact of future expenditures on unproved properties. The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. At December 31, 2001, no such contractual arrangements existed. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, the Company has also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and reclamation and environmental remediation costs. Deducting future income tax expenses then reduces the estimated pretax future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax cash flows relating to the Company's proved oil and gas reserves less the tax basis of the properties involved. At December 31, 2001, there were no legislated future tax rate changes. The future income tax expenses give effect to permanent differences and tax credits and allowances relating to the company's proved oil and gas reserves. The resultant future net cash flows are reduced to present value amounts by applying the SFAS No. 69 mandated 10% discount factor. The result is referred to as "Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes".
2001 2000 1999 ---- ---- ---- ($ MILLIONS) Future cash inflows.......................................... 2,266 8,176 3,272 Future production and development costs...................... (652) (633) (1,053) Other related future costs................................... (283) (175) (133) Future income tax expenses................................... (521) (3,426) (789) ---- ----- ----- Future net cash flows......................................... 810 3,942 1,297 Discount at 10 %.............................................. (370) (2,009) (548) ---- ----- ----- Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes................................... 440 1,933 749 === ===== =====
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PRODUCTION OF PROVED OIL AND GAS RESERVES AFTER INCOME TAXES
2001 2000 1999 ---- ---- ---- ($ MILLIONS) Balance, beginning of year.............................................. 1,933 749 797 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas net of related costs............... (297) (275) (192) Revisions to estimates of proved reserves: Prices.............................................................(3,055) 3,886 458 Development costs................................................... (50) (3) (68) Production costs.................................................... (9) 55 (25) Quantities.......................................................... (2) (363) (175) Other............................................................... (16) (237) (81) Extensions, discoveries, and improved recovery less related costs...... 23 177 46 Development costs incurred during the period........................... 81 69 70 Purchases of reserves in place......................................... - 41 - Sales of reserves in place............................................. (1) (989) (130) Accretion of discount.................................................. 361 115 113 Income taxes.......................................................... 1,472 (1,292) (64) ----- ------- ---- Balance, end of year..................................................... 440 1,933 749 === ===== ===