UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) ----- OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended March 31, 2002 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) ----- OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 000-30176 DEVON ENERGY CORPORATION (Exact Name of Registrant as Specified in its Charter) DELAWARE 73-1567067 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification Number) 20 NORTH BROADWAY OKLAHOMA CITY, OKLAHOMA 73102 -8260 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code: (405) 235-3611 Not applicable - -------------------------------------------------------------------------------- Former name, former address and former fiscal year, if changed from last report. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]. The number of shares outstanding of Registrant's common stock, par value $.10, as of April 30, 2002, was 156,338,000. 1 of 48 total pages
DEVON ENERGY CORPORATION Index to Form 10-Q Quarterly Report to the Securities and Exchange Commission <Table> <Caption> Page No. <S> <C> <C> Part I. Financial Information Item 1. Consolidated Financial Statements Consolidated Balance Sheets, March 31, 2002 (Unaudited) 4 and December 31, 2001 Consolidated Statements of Operations (Unaudited), 5 For the Three Months Ended March 31, 2002 and 2001 Consolidated Statements of Comprehensive Earnings 6 (Unaudited), For the Three Months Ended March 31, 2002 and 2001 Consolidated Statements of Cash Flows (Unaudited), 7 For the Three Months Ended March 31, 2002 and 2001 Notes to Consolidated Financial Statements 8 Item 2. Management's Discussion and Analysis of Financial 21 Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk 45 Part II. Other Information Item 6. Exhibits and Reports on Form 8-K 47 </Table> DEFINITIONS As used in this document: "Mcf" means thousand cubic feet "Bcf" means billion cubic feet "Bbl" means barrel "MMBbls" means million barrels "Boe" means equivalent barrels of oil "Mboe" means thousand equivalent barrels of oil "MMBoe" means million equivalent barrels of oil "Oil" includes crude oil and condensate "NGLs" means natural gas liquids 2
DEVON ENERGY CORPORATION PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2002 AND 2001 (FORMING A PART OF FORM 10-Q QUARTERLY REPORT TO THE SECURITIES AND EXCHANGE COMMISSION) 3
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN MILLIONS, EXCEPT SHARE DATA) <Table> <Caption> MARCH 31, DECEMBER 31, 2002 2001 ------------ ------------ (UNAUDITED) <S> <C> <C> ASSETS Current assets: Cash and cash equivalents $ 367 193 Accounts receivable 680 537 Inventories 53 41 Fair value of financial instruments -- 195 Deferred income taxes 23 -- Income taxes receivable -- 68 Investments and other current assets 47 47 ------------ ------------ Total current assets 1,170 1,081 ------------ ------------ Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($2,626 and $1,939 excluded from amortization in 2002 and 2001, respectively) 19,140 15,598 Less accumulated depreciation, depletion and amortization 6,877 6,570 ------------ ------------ 12,263 9,028 Investment in ChevronTexaco Corporation common stock, at fair value 640 636 Fair value of financial instruments -- 31 Goodwill 3,575 2,206 Other assets 329 202 ------------ ------------ Total assets $ 17,977 13,184 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade 544 465 Revenues and royalties due to others 232 170 Income taxes payable 9 30 Accrued interest payable 41 102 Merger related expenses payable 24 7 Fair value of financial instruments 35 15 Deferred income taxes -- 57 Accrued expenses and other current liabilities 176 73 ------------ ------------ Total current liabilities 1,061 919 ------------ ------------ Other liabilities 292 179 Debentures exchangeable into shares of ChevronTexaco Corporation common stock 652 649 Other long-term debt 8,236 5,940 Deferred revenue 33 51 Fair value of financial instruments 69 45 Deferred income taxes 2,943 2,142 Stockholders' equity: Preferred stock of $1.00 par value ($100 liquidation value) Authorized 4,500,000 shares; issued 1,500,000 in 2002 and 2001 1 1 Common stock of $.10 par value Authorized 400,000,000 shares; issued 159,928,000 in 2002 and 129,886,000 in 2001 16 13 Additional paid-in capital 5,156 3,610 Accumulated deficit (95) (147) Accumulated other comprehensive loss (197) (28) Treasury stock, at cost: 3,754,000 shares in 2002 and 2001 (190) (190) ------------ ------------ Total stockholders' equity 4,691 3,259 ------------ ------------ Total liabilities and stockholders' equity $ 17,977 13,184 ============ ============ </Table> See accompanying notes to consolidated financial statements 4
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) <Table> <Caption> THREE MONTHS ENDED MARCH 31, --------------------------- 2002 2001 ------------ ------------ (UNAUDITED) <S> <C> <C> REVENUES Oil sales $ 254 254 Gas sales 468 725 Natural gas liquids sales 56 32 Marketing and midstream revenue 160 20 ------------ ------------ Total revenues 938 1,031 ------------ ------------ PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 170 123 Transportation costs 38 17 Production taxes 22 45 Marketing and midstream costs and expenses 125 16 Depreciation, depletion and amortization of property and equipment 320 183 Amortization of goodwill -- 8 General and administrative expenses 49 22 ------------ ------------ Total production and operating costs and expenses 724 414 ------------ ------------ Earnings from operations 214 617 OTHER INCOME (EXPENSES) Interest expense (124) (34) Effects of changes in foreign currency exchange rates (4) -- Change in fair value of financial instruments (17) (14) Other income 15 8 ------------ ------------ Net other expenses (130) (40) ------------ ------------ Earnings before income tax expense and cumulative effect of change in accounting principle 84 577 INCOME TAX EXPENSE Current 1 144 Deferred 21 82 ------------ ------------ Total income tax expense 22 226 ------------ ------------ Earnings before cumulative effect of change in accounting principle 62 351 Cumulative effect of change in accounting principle, net of income tax expense of $32 million -- 49 ------------ ------------ Net earnings 62 400 Preferred stock dividends 2 2 ------------ ------------ Net earnings applicable to common shareholders $ 60 398 ============ ============ Net earnings before cumulative effect of change in accounting principle per average common share outstanding: Basic $ 0.41 2.70 ============ ============ Diluted $ 0.40 2.59 ============ ============ Net earnings per average common share outstanding: Basic $ 0.41 3.08 ============ ============ Diluted $ 0.40 2.96 ============ ============ Weighted average common shares outstanding - basic 148 129 ============ ============ Weighted average common shares outstanding - diluted 150 135 ============ ============ </Table> See accompanying notes to consolidated financial statements. 5
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (IN MILLIONS) <Table> <Caption> THREE MONTHS ENDED MARCH 31, --------------------------- 2002 2001 ------------ ------------ (UNAUDITED) <S> <C> <C> Net earnings $ 62 400 Other comprehensive earnings (loss), net of tax: Foreign currency translation adjustments (2) (19) Cumulative effect of change in accounting principle -- (37) Reclassification adjustment for derivative losses (gains) reclassified into oil and gas sales (42) 5 Change in fair value of outstanding hedging positions (128) 13 Unrealized gains on marketable securities 3 15 ------------ ------------ Comprehensive earnings (loss) $ (107) 377 ============ ============ </Table> See accompanying notes to consolidated financial statements. 6
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) <Table> <Caption> THREE MONTHS ENDED MARCH 31, --------------------------- 2002 2001 ------------ ------------ (UNAUDITED) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net earnings $ 62 400 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation, depletion and amortization of property and equipment 320 183 Amortization of goodwill -- 8 Accretion of discounts on long-term debt, net 8 6 Effects of changes in foreign currency exchange rates 4 -- Change in fair value of financial instruments 17 14 Cumulative effect of change in accounting principle -- (49) Deferred income tax expense 21 82 Changes in assets and liabilities, net of acquisitions of businesses: Decrease (increase) in: Accounts receivable 12 79 Inventories 3 7 Prepaid expenses 5 (24) Other assets (123) (13) Increase (decrease) in: Accounts payable 7 2 Income taxes payable 93 97 Accrued expenses and other current liabilities (40) (21) Deferred revenue (18) (16) Long-term other liabilities 1 2 ------------ ------------ Net cash provided by operating activities 372 757 ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of property and equipment 227 22 Capital expenditures, including acquisitions of businesses (2,190) (346) Decrease in other assets 2 -- ------------ ------------ Net cash used in investing activities (1,961) (324) ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings of long-term debt, net of issuance costs 3,742 63 Principal payments on long-term debt (1,979) (118) Issuance of common stock, net of issuance costs 9 32 Repurchase of common stock -- (13) Dividends paid on common stock (8) (7) Dividends paid on preferred stock (2) (2) Decrease in long-term other liabilities -- (5) ------------ ------------ Net cash provided by (used in) financing activities 1,762 (50) ------------ ------------ Effect of exchange rate changes on cash 1 (1) ------------ ------------ Net increase in cash and cash equivalents 174 382 Cash and cash equivalents at beginning of period 193 228 ------------ ------------ Cash and cash equivalents at end of period $ 367 610 ============ ============ </Table> See accompanying notes to consolidated financial statements. 7
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The accompanying consolidated financial statements and notes thereto have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in Devon's 2001 Annual Report on Form 10-K. In the opinion of Devon's management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of March 31, 2002, and the results of their operations and their cash flows for the three month periods ended March 31, 2002 and 2001. Certain of the 2001 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2002 presentation. 2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION Mitchell Energy & Development Corp. Merger On January 24, 2002, Devon completed its acquisition of Mitchell Energy & Development Corp. ("Mitchell"). Under the terms of this merger, Devon issued approximately 30 million shares of Devon common stock and paid $1.6 billion in cash to the Mitchell stockholders. The cash portion of the acquisition was funded from borrowings under a $3.0 billion senior unsecured term loan credit facility (see Note 3). Devon acquired Mitchell for the significant development and exploitation projects in each of Mitchell's core areas, increased marketing and midstream operations and increased exposure to the North American natural gas market. The calculation of the purchase price and the preliminary allocation to assets and liabilities as of January 24, 2002, are shown below. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and fair value of the assets and liabilities as of the acquisition date have not been completed. 8
<Table> <Caption> (IN MILLIONS, EXCEPT SHARE PRICE) <S> <C> Calculation and preliminary allocation of purchase price: Shares of Devon common stock issued to Mitchell stockholders 30 Average Devon stock price $ 50.95 ----------- Fair value of common stock issued $ 1,512 Cash paid to Mitchell stockholders, calculated at $31 per outstanding common share of Mitchell 1,573 ----------- Fair value of Devon common stock and cash to be issued to Mitchell stockholders 3,085 Plus estimated acquisition costs incurred 90 Plus fair value of Mitchell employee stock options assumed by Devon 27 ----------- Total purchase price 3,202 Plus fair value of liabilities assumed by Devon: Current liabilities 177 Long-term debt 506 Other long-term liabilities 129 Deferred income taxes 799 ----------- Total purchase price plus liabilities assumed $ 4,813 =========== Fair value of assets acquired by Devon: Current assets 169 Proved oil and gas properties 1,535 Unproved oil and gas properties 639 Gas services facilities and equipment 1,000 Other property and equipment 14 Other assets 83 Goodwill (none deductible for income taxes) 1,373 ----------- Total fair value of assets acquired $ 4,813 =========== </Table> Anderson Exploration Ltd. Acquisition On October 12, 2001, Devon accepted all of the Anderson common shares tendered by Anderson stockholders in the tender offer, which represented approximately 97% of the outstanding Anderson common shares. On October 17, 2001, Devon completed its acquisition of Anderson by a compulsory acquisition under the Canada Business Corporations Act of the remaining 3% of Anderson common shares. The cost to Devon of acquiring Anderson's outstanding common shares and paying for the intrinsic value of Anderson's outstanding options and appreciation rights was approximately $3.5 billion, which was funded from the sale of $3.0 billion of debt securities and borrowings under a $3.0 billion senior unsecured term loan credit facility (see Note 3). Pro Forma Information Set forth in the following table is certain unaudited pro forma financial information for the three-month periods ended March 31, 2002 and 2001. The information for the three-month periods ended March 31, 2002 and 2001, has been prepared assuming the Anderson acquisition and the Mitchell merger were consummated on January 1, 2001. All pro forma information is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transactions had occurred in the past, Devon's operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Devon would have achieved if the transactions had occurred on January 1, 2001. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions. 9
The following should be considered in connection with the pro forma financial information presented: - On February 12, 2001, Anderson acquired all of the outstanding shares of Numac Energy Inc. The summary unaudited pro forma combined statements of operations do not include any results from Numac's operations prior to February 12, 2001. - Anderson had a compensation plan pursuant to which it periodically issued awards referred to as share appreciation rights under which employees could earn compensation based on increases in the market price of Anderson's stock. Anderson awarded these rights in lieu of stock option grants. Pro forma general and administrative expenses reported in the accompanying unaudited pro forma statements of operations for the three-month period ended March 31, 2001 include $3 million of expenses related to these plans. After taxes, these plans had the effect of decreasing unaudited pro forma net earnings in the 2001 period by $2 million. Devon acquired all outstanding rights as part of the Anderson acquisition. Accordingly, these rights will not affect Devon's net earnings subsequent to the closing of the Anderson acquisition. - Mitchell has compensation plans pursuant to which it periodically issued awards referred to as "bonus units" under which employees could earn compensation based on increases in the market price of Mitchell common stock. Mitchell generally awarded these bonus units in lieu of stock option grants. Pro forma general and administrative expenses reported in the accompanying unaudited pro forma statements of operations for the three-month periods ended March 31, 2002 and 2001 include $2 million of income and $1 million of expenses, respectively related to these plans. After taxes, these plans had the effect of decreasing unaudited pro forma net earnings in the 2002 period by $1 million and increasing unaudited pro forma net earnings in the 2001 period by $1 million. Devon will not issue such bonus units after the merger. - Devon's historical results of operations for the three-month period ended March 31, 2001 include $8 million of amortization expense for goodwill related to previous mergers. As of January 1, 2002, in accordance with new accounting pronouncements, such goodwill is no longer amortized, but instead will be tested for impairment at least annually. No goodwill amortization expense has been recognized in the pro forma statements of operations for the goodwill related to the Anderson acquisition and the Mitchell merger. 10
<Table> <Caption> PRO FORMA INFORMATION THREE MONTHS ENDED MARCH 31 (IN MILLIONS, EXCEPT PER SHARE AMOUNTS AND PRODUCTION VOLUMES) 2002 2001 ------------ ------------ <S> <C> <C> REVENUES Oil sales $ 256 $ 335 Gas sales 490 1,241 Natural gas liquids sales 61 95 Marketing and midstream revenue 230 434 ------------ ------------ Total revenues 1,037 2,105 ------------ ------------ PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 174 187 Transportation costs 41 36 Production taxes 23 57 Marketing and midstream costs and expenses 189 387 Depreciation, depletion and amortization of property and equipment 339 315 Amortization of goodwill -- 8 General and administrative expenses 55 45 Expenses related to mergers -- -- Reduction of carrying value of oil and gas properties -- -- ------------ ------------ Total production and operating costs and expenses 821 1,035 ------------ ------------ Earnings from operations 216 1,070 OTHER INCOME (EXPENSES) Interest expense (125) (121) Effects of changes in foreign currency exchange rates (4) (13) Change in fair value of financial instruments (17) (41) Other income 15 7 ------------ ------------ Net other expenses (131) (168) ------------ ------------ Earnings before income tax expense and cumulative effect of change in accounting principle 85 902 INCOME TAX EXPENSE Current 1 185 Deferred 22 173 ------------ ------------ Total income tax expense 23 358 ------------ ------------ Earnings before cumulative effect of change in accounting principle 62 544 Cumulative effect of change in accounting principle -- 49 ------------ ------------ Net earnings 62 593 Preferred stock dividends 2 2 ------------ ------------ Net earnings applicable to common stockholders $ 60 $ 591 ============ ============ Net earnings before cumulative effect of change in accounting principle per average common share outstanding: Basic $ 0.38 $ 3.43 ============ ============ Diluted $ 0.38 $ 3.29 ============ ============ Net earnings per average common share outstanding: Basic $ 0.38 $ 3.74 ============ ============ Diluted $ 0.38 $ 3.59 ============ ============ Weighted average common shares outstanding - basic 156 158 ============ ============ Weighted average common shares outstanding - diluted 158 165 ============ ============ Production volumes: Oil (MMBbls) 14 14 Gas (Bcf) 205 192 NGLs (MMBbls) 5 4 MMBoe 53 50 </Table> 11
3. LONG-TERM DEBT $3 Billion Term Loan Credit Facility Prior to December 31, 2001, Devon used proceeds of $1 billion on this facility to partially fund the Anderson acquisition. The remaining $2 billion of availability was utilized upon the closing of the Mitchell acquisition on January 24, 2002. As of March 31, 2002, $2.1 billion remained outstanding under this term loan credit facility. The source of the repayments made during the quarter were from the issuance of $1 billion of debt securities discussed below and $100 million from the sale of certain properties. Additional repayments of $445 million from the sale of certain properties have been made between April 1, 2002 and May 3, 2002. Debt Securities On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15, 2032. The debt securities are unsecured and unsubordinated obligations of Devon. The proceeds from the issuance of these debt securities were used to pay down $820 million on the $3 billion term loan credit facility. The remaining $166 million of proceeds, net of discounts and issuance costs, will be used in June 2002 to partially fund the early extinguishment of 8.75% senior notes due June 15, 2007. The notes are redeemable by Devon on June 15, 2002, at 104.375% of principal, or approximately $183 million. Commercial Paper As of March 31, 2002, Devon had $156 million of borrowings under its commercial paper program at an average rate of 2.6%. Because Devon has the intent and ability to refinance the balance due with borrowings under its Credit Facilities, the $156 million outstanding under the commercial paper program was classified as long-term debt on the March 31, 2002 consolidated balance sheet. Revolving Credit Facilities As of March 31, 2002, Devon had $13 million of borrowings under its Canadian facility at an average rate of 3.8%. 4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Devon has periodically entered into oil and gas financial instruments and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are predominantly based on U.S. dollar prices. The hedging instruments are usually placed with counterparties that Devon believes are minimal credit risks. It is Devon's policy to only enter into derivative contracts with investment grade rated counterparties deemed by management to be competent and competitive market makers. The oil 12
and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon. As of March 31, 2002, $35 million of net deferred losses on derivative instruments in "accumulated other comprehensive loss" are expected to be reclassified to earnings from operations during the next 12 months. Transactions and events expected to occur over the next 12 months that will necessitate reclassifying these derivatives' losses to earnings from operations are primarily the production and sale of oil and gas which includes the production hedged under the various derivative instruments. The maximum term over which Devon is hedging exposures to the variability of cash flows for commodity price risk is 21 months. Devon recorded in its statements of operations a loss of $17 million and $14 million in the first quarter of 2002 and 2001, respectively, for the change in fair value of derivative instruments that do not qualify for hedge accounting treatment. Included in the first quarter 2002 loss are net gains of approximately $7 million related to (i) the ineffectiveness of the various cash flow hedges and (ii) the component of the derivative instrument gain or loss excluded from the assessment of hedge effectiveness. 5. GOODWILL Effective January 1, 2002, Devon adopted the remaining provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Asset (SFAS No. 142). Under SFAS No. 142, goodwill and intangible assets with indefinite useful lives are no longer amortized, but are instead tested for impairment at least annually. Devon will perform an assessment of the fair value of the recorded goodwill as of January 1, 2002. Devon has until June 30, 2002, to determine the fair value of its reporting units and compare such fair value to each reporting unit's carrying value. To the extent a reporting unit's carrying value exceeds its fair value, an indication exists that the reporting unit's goodwill may be impaired and Devon must perform the second step of the transitional impairment test. In the second step, Devon must compare the implied fair value of the reporting unit's goodwill, determined by allocating the reporting unit's fair value to all of it assets (recognized and unrecognized) and liabilities in a manner similar to a purchase price allocation in accordance with SFAS No. 141, Business Combinations, to its carrying value, both of which would be measured as of January 1, 2002. This second step is required to be completed as soon as possible, but no later than the end of 2002. Any transitional impairment will be recognized as the cumulative effect of a change in accounting principle in Devon's 2002 statement of operations. As of January 1, 2002, Devon had unamortized goodwill in the amount of $2.2 billion, which was subject to the transition goodwill impairment assessment provisions of SFAS No. 142. Devon has not completed the transitional impairment assessment as of March 31, 2002. However, Devon does not expect that a transitional impairment will be required to be recognized. 13
As a result of the January 2002 Mitchell acquisition, goodwill increased $1.4 billion to $3.6 billion at March 31, 2002. All of the Mitchell-related goodwill is recorded in Devon's U.S. segment. Following is a reconciliation of reported net income and the related earnings per share amounts assuming the provisions of SFAS No. 142 had been adopted as of January 1, 2001. <Table> <Caption> FOR THE THREE MONTHS ENDED MARCH 31, 2002 2001 ------------- ------------- (IN MILLIONS) <S> <C> <C> Net earnings applicable to common shareholders, as reported $ 60 398 Add back amortization of goodwill -- 8 ------------- ------------- Net earnings applicable to common shareholders, as adjusted 60 406 ============= ============= Basic earnings per share: Net earnings applicable to common shareholders, as reported $ 0.41 3.08 Amortization of goodwill -- 0.07 ------------- ------------- Net earnings applicable to common shareholders, as adjusted $ 0.41 3.15 ============= ============= Diluted earnings per share: Net earnings applicable to common shareholders, as reported $ 0.40 2.96 Amortization of goodwill -- 0.07 ------------- ------------- Net earnings applicable to common shareholders, as adjusted $ 0.40 3.03 ============= ============= </Table> 6. EARNINGS PER SHARE The following tables reconcile the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month periods ended March 31, 2002 and 2001. Options to purchase approximately 3.4 million shares of Devon's common stock with exercise prices ranging from $42.41 per share to $89.66 per share (with a weighted average price of $53.63 per share) were outstanding at March 31, 2002, but were not included in the computation of diluted earnings per share for the first quarter of 2002 because the options' exercise price exceeded the average market price of Devon's common stock during the first quarter. Similarly, options to purchase approximately 0.8 million shares of Devon's common stock with exercise prices ranging from $58.84 per share to $89.66 per share (with a weighted average price of $66.49 per share) were excluded from the diluted earnings per share calculation for the first quarter of 2001. The excluded options for the 2002 period expire between April 10, 2002 and December 4, 2011. 14
<Table> <Caption> NET EARNINGS NET APPLICABLE COMMON EARNINGS TO COMMON SHARES PER STOCKHOLDERS OUTSTANDING SHARE ------------- ------------- ------------- (IN MILLIONS) THREE MONTHS ENDED MARCH 31, 2002: <S> <C> <C> <C> Basic earnings per share $ 60 148 $ 0.41 ============= Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options -- 2 ------------- ------------- Diluted earnings per share $ 62 150 $ 0.40 ============= ============= ============= THREE MONTHS ENDED MARCH 31, 2001: Basic earnings per share $ 398 129 $ 3.08 ============= Dilutive effect of: Potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $1 million) 2 4 Potential common shares issuable upon the exercise of outstanding stock options -- 2 ------------- ------------- Diluted earnings per share $ 400 135 $ 2.96 ============= ============= ============= </Table> The senior convertible debentures were not included in the 2002 dilution calculation because the inclusion was anti-dilutive. 7. SUPPLEMENTAL CASH FLOW INFORMATION Cash payments for interest in the first quarter of 2002 and 2001 were approximately $185 million and $25 million, respectively. Cash receipts for federal, state and foreign income taxes in first quarter 2002 were approximately $89 million. Cash payments for federal, state and foreign income taxes in 2001 were approximately $47 million. 15
The first quarter 2002 Mitchell acquisition involved non-cash consideration as presented below: <Table> <Caption> 2002 ------------- (IN MILLIONS) <S> <C> Value of common stock issued $ 1,512 Employee stock options assumed 27 Liabilities assumed 812 Deferred tax liability created 799 --------- Fair value of assets acquired with non-cash consideration $ 3,150 ========= </Table> 8. SEGMENT INFORMATION Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three reportable segments: its operations in the U.S., its operations in Canada and its international operations outside of North America. Substantially all of these segments' operations involve oil and gas producing activities. Following is certain financial information regarding Devon's segments for the first quarters of 2002 and 2001. The revenues reported are all from external customers. <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> AS OF MARCH 31, 2002: Current assets $ 766 140 264 1,170 Property and equipment, net of accumulated depreciation, depletion and amortization 7,153 4,378 732 12,263 Investment in ChevronTexaco Corporation common stock 640 -- -- 640 Goodwill 1,582 1,924 69 3,575 Other assets 285 34 10 329 ------------ ------------ ------------ ------------ Total assets $ 10,426 6,476 1,075 17,977 ============ ============ ============ ============ Current liabilities 559 353 149 1,061 Other liabilities 274 7 11 292 Debentures exchangeable into shares of ChevronTexaco Corporation common stock 652 -- -- 652 Other long-term debt 3,603 4,633 -- 8,236 Deferred revenue 33 -- -- 33 Fair value of financial instruments 64 5 -- 69 Deferred income taxes 1,559 1,320 64 2,943 Stockholders' equity 3,682 158 851 4,691 ------------ ------------ ------------ ------------ Total liabilities and stockholders' equity $ 10,426 6,476 1,075 17,977 ============ ============ ============ ============ </Table> 16
8. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ---------- ---------- ---------- ---------- (IN MILLIONS) <S> <C> <C> <C> <C> THREE MONTHS ENDED MARCH 31, 2002: REVENUES Oil sales $ 130 82 42 254 Gas sales 303 163 2 468 Natural gas liquids sales 35 20 1 56 Marketing and midstream revenues 158 2 -- 160 ---------- ---------- ---------- ---------- Total revenues 626 267 45 938 ---------- ---------- ---------- ---------- PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 91 61 18 170 Transportation costs 22 16 -- 38 Production taxes 21 1 -- 22 Marketing and midstream costs and expenses 125 -- -- 125 Depreciation, depletion and amortization of property and equipment 204 105 11 320 General and administrative expenses 35 9 5 49 ---------- ---------- ---------- ---------- Total production and operating costs and expenses 498 192 34 724 ---------- ---------- ---------- ---------- Earnings from operations 128 75 11 214 OTHER INCOME (EXPENSES) Interest expense (49) (73) (2) (124) Effects of changes in foreign currency exchange rates -- (1) (3) (4) Change in fair value of financial instruments (20) 3 -- (17) Other income 9 3 3 15 Net other expenses (60) (68) (2) (130) ---------- ---------- ---------- ---------- Earnings before income tax expense 68 7 9 84 INCOME TAX EXPENSE (BENEFIT) Current 6 1 (6) 1 Deferred 5 3 13 21 ---------- ---------- ---------- ---------- Total income tax expense 11 4 7 22 ---------- ---------- ---------- ---------- Net earnings 57 3 2 62 Preferred stock dividends 2 -- -- 2 ---------- ---------- ---------- ---------- Net earnings applicable to common shareholders $ 55 3 2 60 ========== ========== ========== ========== Capital expenditures, including acquisitions of businesses $ 1,922 239 29 2,190 ========== ========== ========== ========== </Table> 17
8. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ---------- ---------- ---------- ---------- (IN MILLIONS) <S> <C> <C> <C> <C> THREE MONTHS ENDED MARCH 31, 2001: REVENUES Oil sales $ 166 28 60 254 Gas sales 643 79 3 725 Natural gas liquids sales 27 5 -- 32 Marketing and midstream revenues 18 2 -- 20 ---------- ---------- ---------- ---------- Total revenues 854 114 63 1,031 ---------- ---------- ---------- ---------- PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 89 15 19 123 Transportation costs 14 3 -- 17 Production taxes 44 1 -- 45 Marketing and midstream costs and expenses 15 1 -- 16 Depreciation, depletion and amortization of property and equipment 149 19 15 183 Amortization of goodwill 8 -- -- 8 General and administrative expenses 20 2 -- 22 ---------- ---------- ---------- ---------- Total production and operating costs and expenses 339 41 34 414 ---------- ---------- ---------- ---------- Earnings from operations 515 73 29 617 OTHER INCOME (EXPENSES) Interest expense (32) (2) -- (34) Change in fair value of financial instruments (14) -- -- (14) Other income (expense) 11 -- (3) 8 ---------- ---------- ---------- ---------- Net other expenses (35) (2) (3) (40) ---------- ---------- ---------- ---------- Earnings before income tax expense and cumulative effect of change in accounting principle 480 71 26 577 INCOME TAX EXPENSE Current 140 1 3 144 Deferred 44 30 8 82 ---------- ---------- ---------- ---------- Total income tax expense 184 31 11 226 ---------- ---------- ---------- ---------- Earnings before cumulative effect of change in accounting principle 296 40 15 351 Cumulative effect of change in accounting principle 49 -- -- 49 ---------- ---------- ---------- ---------- Net earnings 345 40 15 400 Preferred stock dividends 2 -- -- 2 ---------- ---------- ---------- ---------- Net earnings applicable to common shareholders $ 343 40 15 398 ========== ========== ========== ========== Capital expenditures $ 231 61 54 346 ========== ========== ========== ========== </Table> 18
9. COMMITMENTS AND CONTINGENCIES Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon's estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon's financial position or results of operations after consideration of recorded accruals although actual amounts could differ from management's estimate. Environmental Matters Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon's consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information. Certain of Devon's subsidiaries acquired in the PennzEnergy merger are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of March 31, 2002, Devon's consolidated balance sheet included $8 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is based in large part on (i) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material. Royalty Matters Numerous gas producers and related parties, including Devon, have been named in various lawsuits filed by private litigants alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The various suits have been consolidated 19
by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suits, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with these lawsuits and no liability has been recorded in connection therewith. 10. SUBSEQUENT EVENT - SALE OF INDONESIAN OPERATIONS On April 19, 2002, Devon completed the sale of all its operations in Indonesia. The total sales price was $262 million, of which $12 million is contingent upon successful completion of certain events. As of March 31, 2002, the Indonesian operations were comprised of net property and equipment of $146 million, net working capital of $40 million and deferred income tax liabilities of $44 million. The results of the Indonesian operations and any related gain on sale will be reported as discontinued operations in the three-month period ended June 30, 2002. 20
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion addresses material changes in results of operations for the three months ended March 31, 2002, compared to the three months ended March 31, 2001, and in financial condition since December 31, 2001. It is presumed that readers have read or have access to Devon's 2001 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management's Discussion and Analysis of Financial Condition and Results of Operations. OVERVIEW Net earnings for the first quarter of 2002 were $62 million, or $0.41 per share. This compares to net earnings of $400 million, or $3.08 per share for the first quarter of 2001. The decrease in first quarter earnings was due to a decline in oil, natural gas and NGL prices, the effects of which were partially offset by an increase in production. On January 24, 2002, Devon completed its acquisition of Mitchell. Under the terms of this merger, Devon issued approximately 30 million shares of Devon common stock and paid $1.6 billion in cash to the Mitchell stockholders. The cash portion of the acquisition was funded from borrowings under a $3.0 billion senior unsecured term loan credit facility. On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15, 2032. The debt securities are unsecured and unsubordinated obligations of Devon. The proceeds from the issuance of these debt securities were used to pay down $820 million on the $3 billion term loan credit facility. The remaining $166 million of proceeds, net of discounts and issuance costs, will be used in June 2002 to partially fund the early extinguishment of 8.75% senior notes due June 15, 2007. The notes are redeemable by Devon on June 15, 2002, at 104.375% of principal, or approximately $183 million. 21
RESULTS OF OPERATIONS Total revenues decreased $93 million, or 9%, in the first quarter of 2002. This was the result of decreases in the average prices of oil, gas and NGLs, partially offset by higher production on a combined Boe basis and an increase in marketing and midstream revenue. Oil, gas and NGL revenues decreased $233 million, or 23%, for the first quarter of 2002 compared to the first quarter of 2001. The quarterly comparisons of production and price changes are shown in the following tables. (Note: Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.) <Table> <Caption> TOTAL --------------------------------- THREE MONTHS ENDED MARCH 31, --------------------------------- 2002 2001 CHANGE --------- --------- --------- <S> <C> <C> <C> PRODUCTION Oil (MMBbls) 14 10 +40% Gas (Bcf) 195 122 +74% NGLs (MMBbls) 4 1 +300% Oil, Gas and NGLs (MMBoe)(1) 51 30 +70% AVERAGE PRICES Oil (Per Bbl) $ 18.69 24.33 -23% Gas (Per Mcf) 2.41 6.49 -63% NGLs (Per Bbl) 12.24 24.55 -50% Oil, Gas and NGLs (Per Boe)(1) 15.38 33.29 -54% (IN MILLIONS) REVENUES Oil $ 254 254 -- Gas 468 725 -35% NGLs 56 32 +75% --------- --------- Combined $ 778 1,011 -23% ========= ========= </Table> 22
<Table> <Caption> DOMESTIC ------------------------------------ THREE MONTHS ENDED MARCH 31, ------------------------------------ 2002 2001 CHANGE ---------- ---------- ---------- <S> <C> <C> <C> PRODUCTION Oil (MMBbls) 7 7 -- Gas (Bcf) 120 95 +26% NGLs (MMBbls) 3 1 +200% Oil, Gas and NGLs (MMBoe)(1) 30 24 +25% AVERAGE PRICES Oil (Per Bbl) $ 19.31 24.85 -22% Gas (Per Mcf) 2.52 6.80 -63% NGLs (Per Bbl) 12.01 23.81 -50% Oil, Gas and NGLs (Per Boe)(1) 15.77 35.43 -55% (IN MILLIONS) REVENUES Oil $ 130 166 -22% Gas 303 643 -53% NGLs 35 27 +30% ---------- ---------- Combined $ 468 836 -44% ========== ========== </Table> <Table> <Caption> CANADA ------------------------------------ THREE MONTHS ENDED MARCH 31, ------------------------------------ 2002 2001 CHANGE ---------- ---------- ---------- <S> <C> <C> <C> PRODUCTION Oil (MMBbls) 5 1 +400% Gas (Bcf) 73 15 +387% NGLs (MMBbls)(1) -- N/M Oil, Gas and NGLs (MMBoe)(1) 18 4 +350% AVERAGE PRICES Oil (Per Bbl) $ 17.44 21.61 -19% Gas (Per Mcf) 2.23 5.23 -57% NGLs (Per Bbl) 12.61 29.45 -57% Oil, Gas and NGLs (Per Boe)(1) 14.36 28.15 -49% (IN MILLIONS) REVENUES Oil $ 82 28 +193% Gas 163 79 +106% NGLs 20 5 +300% ---------- ---------- Combined $ 265 112 +137% ========== ========== </Table> 23
<Table> <Caption> INTERNATIONAL ------------------------------------ THREE MONTHS ENDED MARCH 31, ------------------------------------ 2002 2001 CHANGE ---------- ---------- ---------- <S> <C> <C> <C> PRODUCTION Oil (MMBbls) 2 2 -- Gas (Bcf) 2 2 -- NGLs (MMBbls) -- -- N/M Oil, Gas and NGLs (MMBoe)(1) 2 2 -- AVERAGE PRICES Oil (Per Bbl) $ 19.48 24.34 -20% Gas (Per Mcf) 1.32 1.31 +1% NGLs (Per Bbl) 14.49 25.00 -42% Oil, Gas and NGLs (Per Boe)(1) 18.16 22.43 -19% (IN MILLIONS) REVENUES Oil $ 42 60 -29% Gas 2 3 -33% NGLs 1 -- N/M ---------- ---------- Combined $ 45 63 -27% ========== ========== </Table> - ---------- (1) Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. The respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content. N/M Not meaningful. The average sales prices per unit of production shown in the preceding tables include the effect of Devon's hedging activities. Following is a comparison of Devon's average sales prices with and without the effect of hedges for the three-month periods ended March 31, 2002 and 2001. <Table> <Caption> WITH HEDGES WITHOUT HEDGES ----------------------- ----------------------- THREE MONTHS ENDED THREE MONTHS ENDED MARCH 31, MARCH 31, ----------------------- ----------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> Oil (per Bbl) $ 18.69 24.33 $ 18.27 25.07 Gas (per Mcf) $ 2.41 6.49 $ 2.12 6.56 NGLs (per Bbl) $ 12.24 24.55 $ 12.24 24.55 Oil, Gas and NGLs (per Boe) $ 15.38 33.29 $ 14.18 33.99 </Table> OIL REVENUES. Oil revenues were essentially flat in the first quarter of 2002. Oil revenues decreased $76 million due to a $5.64 per barrel decrease in the average price of oil in 2002. An increase in 2002's production of 4 million barrels caused oil revenues to increase by 24
$76 million. The October 2001 Anderson acquisition and the January 2002 Mitchell acquisition accounted for the increased production. GAS REVENUES. Gas revenues decreased $257 million in 2002's first quarter. Of this total decrease, $795 million was due to a $4.08 per Mcf decrease in the average gas price in the first quarter of 2002. This was partially offset by a $538 million increase related to a production increase of 73 Bcf in the 2002 period. The Anderson and Mitchell acquisitions accounted for the increased production. NGL REVENUES. NGL revenues increased $24 million in the first quarter of 2002. Of this total increase, $80 million was due to a 3 million barrel increase in 2002 production. The Anderson and Mitchell acquisitions accounted for all of the increase. This was partially offset by a $56 million decrease related to a $12.31 per barrel decrease in the average NGL price in the first quarter of 2002. MARKETING AND MIDSTREAM REVENUES. Marketing and midstream revenues increased $140 million, or 692%, in the first quarter of 2002. The Mitchell acquisition included significant marketing and midstream assets which accounts for the increase in revenues. PRODUCTION AND OPERATING EXPENSES. The components of production and operating expenses for the first quarter of 2002 and 2001 are set forth in the following tables. <Table> <Caption> TOTAL ------------------------------------ THREE MONTHS ENDED MARCH 31, ------------------------------------ 2002 2001 CHANGE ---------- ---------- ---------- <S> <C> <C> <C> ABSOLUTE (Millions) Recurring lease operating expenses $ 161 116 +39% Well workover expenses 9 7 +29% Transportation costs 38 17 +124% Production taxes 22 45 -51% ---------- ---------- Total production and operating expenses $ 230 185 +24% ========== ========== PER BOE Recurring lease operating expenses 3.20 3.82 -16% Well workover expenses 0.16 0.21 -24% Transportation costs 0.75 0.57 +32% Production taxes 0.44 1.47 -70% ---------- ---------- Total production and operating expenses $ 4.55 6.07 -25% ========== ========== </Table> Recurring lease operating expenses increased $45 million in the first quarter of 2002. The Anderson and Mitchell acquisitions accounted for $58 million of the increase. The historical 25
Devon lease operating expenses decreased $13 million due to lower fuel and electricity costs as well as lower third-party field service costs. Transportation costs increased $21 million, primarily due to an increase in gas production from the Anderson and Mitchell acquisitions and increases in transportation costs. Production taxes decreased $23 million in the 2002 quarter. The majority of Devon's production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 44% decrease in domestic oil, gas and NGL revenues in the first quarter of 2002 was the primary cause of the production tax decrease. MARKETING AND MIDSTREAM COSTS AND EXPENSES. Marketing and midstream costs and expenses increased $109 million, or 681%, in the first quarter of 2002. The Mitchell acquisition included significant marketing and midstream assets which accounts for the increase in costs and expenses. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES ("DD&A"). Oil and gas property related DD&A increased $124 million, or 71%, from $174 million in the first quarter of 2001 to $298 million in the first quarter of 2002. Oil and gas property related DD&A expense increased $116 million due to the 70% increase in combined oil, gas and NGLs production in 2002. Additionally, an increase in the combined U.S., Canadian and international DD&A rate from $5.73 per Boe in 2001 to $5.88 per Boe in 2002 caused oil and gas property related DD&A to increase by $8 million. Non-oil and gas property DD&A expense increased $13 million from $9 million in the first quarter of 2001 compared to $22 million the first quarter of 2002. Depreciation of the marketing and midstream assets acquired in the January 2002 Mitchell acquisitions accounted for the increase. GENERAL AND ADMINISTRATIVE EXPENSES ("G&A"). Devon's net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full-cost method of accounting. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property's life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. The following table is a summary of G&A expenses by component for the first quarter of 2002 and 2001. 26
<Table> <Caption> THREE MONTHS ENDED MARCH 31, ------------------------- 2002 2001 ---------- ---------- (IN MILLIONS) <S> <C> <C> Gross G&A $ 91 51 Capitalized G&A (22) (16) Reimbursed G&A (20) (13) ---------- ---------- Net G&A $ 49 22 ========== ========== </Table> Net G&A increased $27 million, or 123%, in the first quarter of 2002 compared to the first quarter of 2001. Gross G&A increased $40 million, or 78%. The increase in gross expenses in the first quarter of 2002 was primarily related to the Anderson and Mitchell acquisitions. G&A was reduced $6 million due to an increase in the amount capitalized as part of oil and gas properties. G&A was also reduced $7 million due to an increase in the amount of reimbursements on operated properties in the 2002 quarter. Changes in both of the capitalized and reimbursed amounts were primarily related to the Anderson and Mitchell acquisitions. INTEREST EXPENSE. Interest expense increased $90 million, or 254%, in 2002's first quarter. An increase in the average debt balance outstanding from $1.9 billion in 2001 to $8.3 billion in 2002 caused interest expense to increase by $90 million. The increase in the average debt balance in the first quarter of 2002 was primarily attributable to the long-term debt issued to complete the Anderson and Mitchell acquisitions. The average interest rate on outstanding debt decreased from 6.8% in the 2001 quarter to 5.8% in the 2002 quarter due to the favorable rates on the borrowings under the $3 billion term loan credit facility. This facility's rates averaged less than 3% during the 2002 quarter. The overall rate decrease caused interest expense to decrease $5 million in the 2002 period. Other items included in interest expense that are not related to the debt balance outstanding were $5 million higher in the 2002 quarter compared to the 2001 quarter. These items include facility and agency fees, amortization of costs and other miscellaneous items. <Table> <Caption> THREE MONTHS ENDED MARCH 31, ------------------------ 2002 2001 ---------- ---------- (IN MILLIONS) <S> <C> <C> Interest on debt outstanding $ 118 33 Amortization of discounts and premiums, net 3 2 Facility and agency fees 1 -- Amortization of capitalized loan costs 1 -- Capitalized interest (1) (1) Other 2 -- ---------- ---------- Total interest expense $ 124 34 ========== ========== </Table> 27
EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES. The devaluation of the Argentine peso resulted in a $3 million loss in the 2002 period. Additionally, as a result of the Anderson acquisition, Devon's Canadian subsidiary assumed certain fixed-rate senior notes which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar from the dates the notes were acquired to the dates of repayment increase or decrease the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. The drop in the Canadian-to-U.S. dollar exchange rate from $0.628 at December 31, 2001 to $0.6275 at March 31, 2001 resulted in a $1 million loss. INCOME TAXES. During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate in the first quarter of 2002 was 26%, compared to 39% estimated in the first quarter of 2001. The lower expected 2002 rate is primarily due to the tax benefits of certain foreign deductions. The 2001 rate was higher than the statutory federal tax rate due to the effect of state taxes, goodwill amortization that was not deductible for income tax purposes and the effect of foreign income taxes. Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS No. 109"), requires that the tax benefit of available tax carryforwards be recorded as an asset to the extent that management assesses the utilization of such carryforwards to be "more likely than not". When the future utilization of some portion of the carryforwards is determined not to be "more likely than not", SFAS No. 109 requires that a valuation allowance be provided to reduce the recorded tax benefits from such assets. Included as deferred tax assets at March 31, 2002, were approximately $157 million of tax related carryforwards. The carryforwards include U.S. federal net operating loss carryforwards, the majority of which do not begin to expire until 2008, U.S. state net operating loss carryforwards which expire primarily between 2002 and 2014, Canadian carryforwards which expire primarily between 2002 and 2008 and minimum tax credits which have no expiration. Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2002 and 2010. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, Devon's management believes that future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expirations. 28
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE. At the time of adoption of SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, Devon recorded a net-of-tax cumulative-effect-type adjustment to net earnings of $49 million gain related to the fair value of derivatives that do not qualify as hedges. This gain included $46 million related to the option embedded in the debentures that are exchangeable into shares of ChevronTexaco Corporation common stock. CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in Part 1, Item 1. CAPITAL EXPENDITURES. Approximately $2.2 billion was spent in the first three months of 2002 for capital expenditures. This total includes $1.7 billion related to the January 2002 Mitchell acquisition and $0.5 billion for the acquisition, drilling or development of oil and gas properties. These amounts compare to first quarter 2001 capital expenditures of $346 million ($332 million of which was related to oil and gas properties). OTHER CASH USES. Devon's common stock dividends were $8 million and $7 million in the first quarter of 2002 and 2001, respectively. Devon also paid $2 million of preferred stock dividends in each of the first quarters of 2002 and 2001. CAPITAL RESOURCES AND LIQUIDITY. Devon's primary source of liquidity has historically been net cash provided by operating activities ("operating cash flow"). This source has been supplemented as needed by accessing credit lines and commercial paper markets and issuing equity securities and long-term debt securities. In 2002, another major source of liquidity will be sales of oil and gas properties. Net cash provided by operating activities ("operating cash flow") continued to be the primary source of capital and liquidity in the first quarter of 2002. Operating cash flow in the first quarter of 2002 was $372 million, compared to $757 million in the first quarter of 2001. The decrease in operating cash flow in the 2002 quarter was primarily caused by the decline in revenues and increased expenses, as discussed earlier in this section. Devon's operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic conditions, weather and other substantially variable factors influence market conditions for these products. These factors are beyond Devon's control and are difficult to predict. To mitigate some of the risk inherent in oil and natural gas prices, Devon has entered into various fixed-price physical delivery contracts and financial price swap contracts to fix the price to be received for a portion of future oil and natural gas production. Additionally, Devon has 29
utilized price collars to set minimum and maximum prices on a portion of its production. The table below provides the volumes associated with these various arrangements as of April 30, 2002. <Table> <Caption> Fixed-Price Physical Price Swap Price Delivery Contracts Contracts Collars Total -------------------- ---------- ------- ----- <S> <C> <C> <C> <C> Oil production (MMBbls) 2002 2 10 10 22 2003 -- -- 6 6 Natural gas production (Bcf) 2002 59 111 177 347 2003 29 37 145 181 2004 26 -- -- 26 </Table> For the years 2005 through 2011, Devon has fixed-price physical delivery contracts covering Canadian natural gas production ranging from 13 Bcf to 19 Bcf per year. Devon also has Canadian gas volumes subject to fixed-price contracts in the years from 2012 through 2016, but the yearly volumes are less than 1 Bcf. By removing the price volatility from the above volumes of oil and natural gas production, Devon has mitigated, but not eliminated, the potential negative effect of declining prices on its operating cash flow. Other sources of liquidity are Devon's revolving lines of credit. As of March 31, 2002, these credit lines totaled $1 billion, of which $831 million was available to Devon for future borrowings. The majority of the revolving credit lines consist of a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). Devon had $13 million of borrowings under its revolving credit facilities at March 31, 2002, at an interest rate of 3.8%. Devon also has access to short-term credit under its commercial paper program. Total borrowings under the U.S. Facility and the commercial paper program may not exceed $725 million. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days. Devon had $156 million of commercial paper debt outstanding at March 31, 2002, at an interest rate of 2.6%. A portion of cash used in the Anderson and Mitchell acquisitions was provided by a $3 billion senior unsecured credit facility. This credit facility, which was entered into in October 2001, has a term of five years. The $3 billion credit facility was fully borrowed upon the closing of the Mitchell acquisition on January 24, 2002. However, as of March 31, 2002, borrowings under this facility have been reduced by $900 million. Debt under this facility was reduced by an additional $445 million from April 1, 2002 through May 3, 2002. Of this total reduction, $820 million came from the issuance of $1 billion of debt securities and $525 million came from 30
proceeds from property sales. The remaining balance outstanding as of May 3, 2002 will mature as follows: <Table> (In Millions) <S> <C> October 15, 2005 $ 87 April 15, 2006 $ 800 October 15, 2006 $ 800 ------- $ 1,687 ======= </Table> This $3 billion facility includes various rate options which can be elected by Devon, including a rate based on LIBOR plus a margin. Through June 17, 2002, this margin is fixed at 100 basis points. Thereafter, the margin will be based on Devon's debt rating. Based on Devon's current debt rating, the margin after June 17, 2002, would be 100 basis points. As of May 3, 2002, Devon had $1.7 billion borrowed under this facility at an average interest rate of 2.9%. Devon's $1 billion revolving credit facilities and its $3 billion term loan credit facility each contain only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization of no more than 70% through June 30, 2002, and no more than 65% thereafter. The credit agreements contain definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in Devon's consolidated financial statements. Per the agreements, total funded debt excludes the debentures that are exchangeable into shares of ChevronTexaco Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments. As of March 31, 2002, Devon's ratio of total funded debt to total capitalization, as defined in its credit agreements, was 60.8%. On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15, 2032. The debt securities are unsecured and unsubordinated obligations of Devon. The proceeds from the issuance of these debt securities were used to pay down $820 million on the $3 billion term loan credit facility. The remaining $166 million of proceeds, net of discounts and issuance costs, will be used in June 2002 to partially fund the early extinguishment of 8.75% senior notes due June 15, 2007. The notes are redeemable by Devon on June 15, 2002, at 104.375% of principal, or approximately $183 million. During 2002, Devon estimates that it will sell certain oil and gas properties (the "Disposition Properties") for between $1.2 billion and $1.5 billion. The Disposition Properties are predominantly those that are either outside of Devon's core operating areas or otherwise do not fit Devon's current strategic objectives. The Disposition Properties are located in the U.S., Canada and International areas. As of May 3, 2002, Devon has closed sales of Disposition Properties totaling $604 million in proceeds, and has signed agreements for an additional $598 million of transactions which are expected to close by the end of the second quarter of 2002. In addition, Devon has 31
identified another $200 million to $300 million of Disposition Properties that could be sold in the second half of the year. A summary of Devon's contractual obligations as of March 31, 2002, is provided in the following table. <Table> <Caption> PAYMENTS DUE BY YEAR -------------------------------------------------------------------------- AFTER 2002 2003 2004 2005 2006 2006 TOTAL -------- -------- -------- -------- -------- -------- -------- (IN MILLIONS) <S> <C> <C> <C> <C> <C> <C> <C> Long-term debt $ -- -- 493 883 1,731 5,899 9,006 Operating leases 32 30 22 15 11 14 124 Drilling obligations 173 17 -- -- -- -- 190 Firm transportation agreements 93 82 65 49 42 219 550 -------- -------- -------- -------- -------- -------- -------- Total $ 298 129 580 947 1,784 6,132 9,870 ======== ======== ======== ======== ======== ======== ======== </Table> Firm transportation agreements represent "ship or pay" arrangements whereby Devon has committed to ship certain volumes of gas for a fixed transportation fee. Devon has entered into these agreements to ensure that Devon can get its gas production to market. Devon expects to have sufficient volumes to ship to satisfy the firm transportation agreements, so that Devon will be receiving equivalent value for the firm transportation payments that it will make. The above table does not include $107 million of letters of credit that have been issued by commercial banks on Devon's behalf which, if funded, would become borrowings under Devon's revolving credit facility. Most of these letters of credit have been granted by Devon's financial institutions to support Devon's Canadian drilling commitments. The $9.0 billion of long-term debt shown in the table excludes $118 million of discounts included in the March 31, 2002, book balance of the debt. REVISIONS TO 2002 ESTIMATES On March 19, 2002, Devon filed a Form 10-K that provided forward-looking estimates for the year 2002. Full-year revisions of those previous estimates are provided herein. The revised estimates reflect the impact of Devon's acquisition of Mitchell Energy & Development Corp. on January 24, 2002 and the anticipated timing of the sales of the Disposition Properties. The full-year revisions also include adjustments to previous estimates, when required, to reflect actual year-to-date results. The revised forward-looking statements provided in this discussion are based on management's examination of historical operating trends, the information which was used to prepare the December 31, 2001 reserve reports and other data in Devon's possession or available from third parties. Devon cautions that its future oil, natural gas and NGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of oil, gas and NGLs. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, 32
environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below. Additionally, Devon cautions that its future gas services revenues and expenses are subject to all of the risks and uncertainties normally incident to the gas services business. These risks include, but are not limited to, price volatility, environmental risks, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipeline throughput, and other risks as outlined below. Also, the financial results of Devon's foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks. SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION ESTIMATES Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and worldwide economic conditions, weather and other substantially variable factors. These factors are beyond Devon's control and are difficult to predict. In addition to volatility in general, Devon's oil, gas and NGL prices may vary considerably due to differences between regional markets, transportation availability and demand for different grades of oil, gas and NGLs. Substantially all of Devon's revenues are attributable to sales, processing and transportation of these three commodities. Consequently, Devon's financial results and resources are highly influenced by price volatility. Estimates for Devon's future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil and gas will continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Also, Devon's international production of oil, natural gas and NGLs is governed by payout agreements with the governments of the countries in which Devon operates. If the payout under these agreements is attained earlier than projected, Devon's net production and proved reserves in such areas could be reduced. Estimates for Devon's future processing and transport of natural gas and NGLs are based on the assumption that market demand and prices for gas and NGLs will continue at levels that allow for profitable processing and transport of these products. There can be no assurance of such stability. The production, transportation, processing and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for Devon's oil, natural gas and NGLs during 2002 will be substantially similar to those of the first three months of 2002, unless otherwise noted. Given the general limitations expressed herein, Devon's forward-looking statements for 2002 are set forth below. Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Those amounts related to Canadian operations have been converted to U.S. dollars using an exchange rate of $0.65 U.S. dollar to $1.00 Canadian dollar. The actual 33
2002 exchange rate may vary materially from this estimated rate. Such variations could have a material effect on the following Canadian estimates. The following forward-looking data excludes the financial and operating effects of potential property acquisitions or divestitures, except for the Mitchell acquisition and except as discussed in "Property Acquisitions and Divestitures". The timing and ultimate results of such acquisition and divestiture activity is difficult to predict, and may vary materially from that discussed in this report. GEOGRAPHIC REPORTING AREAS FOR 2002 The following estimates of production, average price differentials and capital expenditures are provided separately for each of the following geographic areas: o the United States; o Canada; and o International, which encompasses all oil and gas properties that lie outside of the United States and Canada. YEAR 2002 POTENTIAL OPERATING ITEMS The estimates related to oil, gas and NGL production, operating costs and DD&A set forth in the following paragraphs are based on estimates for Devon's properties other than those that have been designated for possible sale (See "Property Acquisitions and Divestitures"). Therefore, the following estimates exclude the results of the potential sale properties for the entire year. Also, all of the estimates related to price swaps and costless price collars are as of April 30, 2002. OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are individual estimates of Devon's oil, gas and NGL production for 2002. On a combined basis, Devon estimates its 2002 oil, gas and NGL production will total between 175.2 and 185.2 MMBoe. Of this total, approximately 92% is estimated to be produced from reserves classified as proved at December 31, 2001. OIL PRODUCTION Devon expects its oil production to total between 36.5 and 38.6 MMBbls. Of this total, approximately 95% is estimated to be produced from reserves classified as proved at December 31, 2001. The expected ranges of production by area are as follows: <Table> <Caption> (MMBbls) ------------ <S> <C> United States 19.7 to 20.8 Canada 14.9 to 15.8 International 1.9 to 2.0 </Table> OIL PRICES - FIXED Through certain forward oil sales agreements assumed in the 2000 Santa Fe Snyder merger, the price on a portion of Devon's 2002 oil production has been fixed. 34
These agreements fixed the price on 2.5 MMBbls of 2002 oil production at an average price of $16.84 per Bbl. It should be noted that these forward sales apply only to production in the first eight months of 2002. Devon has executed price swaps attributable to 8 MMBbls of domestic production at an average price of $23.85 per Bbl. Additionally, Devon has entered into price swaps attributable to Canadian production of 1.6 MMBbls at an average price of $20.33 per Bbl. OIL PRICES - FLOATING For oil production for which prices have not been fixed, Devon's average prices are expected to differ from the NYMEX price as set forth in the following table. <Table> <Caption> EXPECTED RANGE OF OIL PRICES LESS THAN NYMEX PRICE ---------------------------- <S> <C> United States ($3.15) to ($2.15) Canada ($5.50) to ($3.50) International ($3.30) to ($2.30) </Table> Devon has also entered into costless price collars that set a floor prices and a ceiling price for 7.3 MMBbls of United States oil production that otherwise is subject to floating prices. The collars have weighted average floor and ceiling prices per Bbl of $23.00 and $28.19, respectively. The floor and ceiling prices are based on the NYMEX price. The NYMEX price is the monthly average of settled prices on each trading day for West Texas Intermediate Crude oil delivered at Cushing, Oklahoma. If the NYMEX price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon's oil revenues for the period. Because Devon's oil volumes are often sold at prices that differ from the NYMEX price due to differing quality (i.e., sweet crude versus sour crude) and transportation costs from different geographic areas, the floor and ceiling prices of the various collars do not reflect actual limits of Devon's realized prices for the production volumes related to the collars. GAS PRODUCTION Devon expects its gas production to total between 733 Bcf and 775 Bcf. Of this total, approximately 90% is estimated to be produced from reserves classified as proved at December 31, 2001. The expected ranges of production are as follows: <Table> <Caption> (BCF) ---------- <S> <C> United States 465 to 492 Canada 268 to 283 </Table> GAS PRICES - FIXED Through various price swaps and fixed-price physical delivery contracts, Devon has fixed the price it will receive on a portion of its natural gas production. The following tables include information on this fixed-price production. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the prices recorded by Devon, and the prices have also been adjusted for the Btu content of the gas hedged. 35
<Table> <Caption> FIRST HALF OF 2002 SECOND HALF OF 2002 -------------------------- -------------------------- Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf <S> <C> <C> <C> <C> United States 268,509 $ 2.91 263,928 $ 2.96 Canada 222,300 $ 2.07 175,548 $ 2.01 </Table> GAS PRICES - FLOATING For the natural gas production for which prices have not been fixed, Devon's average prices are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is determined to be the first-of-month South Louisiana Henry Hub price index as published monthly in Inside FERC. <Table> <Caption> EXPECTED RANGE OF GAS PRICES GREATER THAN (LESS THAN) NYMEX PRICE ------------------------------------ <S> <C> United States ($0.45) to $0.05 Canada ($0.70) to ($0.20) </Table> Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its natural gas production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon's gas revenues for the period. Because Devon's gas volumes are often sold at prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices of the various collars do not reflect actual limits of Devon's realized prices for the production volumes related to the collars. Devon has entered into costless collars concerning its 2002 gas production. To simplify presentation, these collars have been aggregated in the following table according to similar floor prices. The floor and ceiling prices shown are weighted averages of the various collars in each aggregated group. The prices shown in the following table have been adjusted to a NYMEX-based price, using Devon's estimates of 2002 differentials between NYMEX and the specific regional indices upon which the collars are based. The floor and ceiling prices related to the domestic collars are based on various regional first-of-the-month price indices as published monthly by Inside FERC. The floor and ceiling prices related to the Canadian collars are based on the AECO index as published by the Canadian Gas Price Reporter. 36
<Table> <Caption> FIRST HALF OF 2002 SECOND HALF OF 2002 ---------------------------------- ---------------------------------- FLOOR CEILING FLOOR CEILING PRICE PRICE PRICE PRICE PER PER PER PER AREA (RANGE OF FLOOR PRICES) MMBtu/DAY MMBtu MMBtu MMBtu/DAY MMBtu MMBtu ---------------------------- --------- -------- -------- --------- -------- -------- <S> <C> <C> <C> <C> <C> <C> United States ($3.38 - $3.65) 285,000 $ 3.51 $ 7.37 285,000 $ 3.51 $ 7.37 United States ($2.95 - $3.05) 130,000 $ 3.00 $ 4.51 --- $ -- $ -- United States ($2.75 - $2.78) 35,000 $ 2.76 $ 3.72 35,000 $ 2.76 $ 3.72 Canada ($3.45 - $3.63) 23,705 $ 3.56 $ 6.73 23,705 $ 3.56 $ 6.73 Canada ($3.10 - $3.23) 9,481 $ 3.17 $ 4.41 --- $ -- $ -- Canada ($2.63 - $2.90) 34,481 $ 2.70 $ 3.79 25,000 $ 2.63 $ 3.58 </Table> NGL PRODUCTION Devon expects its production of NGLs to total between 16.5 million barrels and 17.4 million barrels. Of this total, 98% is estimated to be produced from reserves classified as proved at December 31, 2001. The expected ranges of production are as follows: <Table> <Caption> (MMBbls) ------------ <S> <C> United States 11.9 to 12.5 Canada 4.6 to 4.9 </Table> MARKETING AND MIDSTREAM REVENUES AND EXPENSES Devon's marketing and midstream revenues and expenses are derived from its natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in response to several factors. The factors include, but are not limited to, changes in production from wells connected to the pipelines and related processing plants, changes in the absolute and relative prices of natural gas and NGLs, provisions of the contract agreements and the amount of repair and workover activity required to maintain anticipated processing levels. These factors increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses. Given these uncertainties, Devon estimates that 2002 marketing and midstream revenues will be between $900 million and $965 million and marketing and midstream expenses will be between $740 million and $780 million. PRODUCTION AND OPERATING EXPENSES Devon's production and operating expenses include lease operating expenses, transportation costs and production taxes. These expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from Devon's property base, changes in production tax rates, changes in the general price level of services and materials that are used in the operation of the properties and the amount of repair and workover activity required. Oil, natural gas and NGL prices also have an effect on lease operating expense and impact the economic feasibility of planned workover projects. Given these uncertainties, Devon estimates that lease operating expenses will be between $545 million and $571 million, transportation costs will be between $153 million and $160 million 37
and production taxes will be between 3.2% and 3.7% of consolidated oil, natural gas and NGL revenues, excluding revenues related to hedges upon which production taxes are not incurred. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2002 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts compared to the costs incurred for such efforts, and the revisions to Devon's year-end 2001 reserve estimates that, based on prior experience, are likely to be made during 2002. Oil and gas property related DD&A expense is expected to be between $1.0 billion and $1.2 billion. Additionally, Devon expects its DD&A expense related to non-oil and gas property fixed assets to total between $94 million and $98 million. This range includes $62 million to $65 million related to marketing and midstream assets. Based on these DD&A amounts and the production estimates set forth earlier, Devon expects its consolidated DD&A rate will be between $6.40 per Boe and $6.76 per Boe. GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the costs of many different goods and services used in support of its business. These goods and services are subject to general price level increases or decreases. In addition, Devon's G&A varies with its level of activity and the related staffing needs as well as with the amount of professional services required during any given period. Should Devon's needs or the prices of the required goods and services differ significantly from current expectations, actual G&A could vary materially from the estimate. Given these limitations, consolidated G&A is expected to be between $189 million and $198 million. INTEREST EXPENSE Future interest rates, debt outstanding and oil, natural gas and NGL prices have a significant effect on Devon's interest expense. Devon can only marginally influence the prices it will receive in 2002 from sales of oil, natural gas and NGLs and the resulting cash flow. The proceeds and the timing of the property sales in 2002 will also affect interest expense. These factors increase the margin of error inherent in estimating future interest expense. Other factors which affect interest expense, such as the amount and timing of capital expenditures, are within Devon's control. Assuming no changes in fixed-rate debt balances during the remainder of 2002 except as discussed herein, Devon's average balance of fixed rate debt during 2002 will be $6.3 billion. The interest expense in 2002 related to this fixed-rate debt will be approximately $464 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of Devon's long-term debt. Devon's floating rate debt is discussed in the following paragraphs. After completion of the Mitchell acquisition, Devon had 100% of its $3.0 billion senior unsecured term loan credit facility borrowed. Interest on borrowings under this facility may be based, at Devon's option, on LIBOR plus a margin determined by Devon's long-term senior unsecured debt ratings. Regardless of the current debt ratings, the margin for borrowings based 38
on LIBOR will be 100 basis points until June 17, 2002. As of May 3, 2002, the average interest rate on this facility was 2.9% and the current balance was $1.7 billion. From time to time, Devon borrows under its $1 billion credit facilities. Borrowings under the U.S. facility, currently set at $725 million, may be borrowed at various rate options including LIBOR plus a margin with interest periods of up to six months. Borrowings under the Canadian facility, currently set at $275 million, may be made at various rate options including LIBOR plus a margin with interest periods up to six months, or Bankers Acceptances plus a margin with interest periods of 30 to 180 days. The current LIBOR margin ranges from 45.0 to 47.5 basis points and the current Bankers Acceptance margin is 45.0 basis points. There were no borrowings under these facilities at March 31, 2002. From time to time, Devon also borrows under its commercial paper facility. Total borrowings under the $725 million U.S. facility and the commercial paper program cannot exceed $725 million. The total borrowed under the commercial paper program was $156 million at March 31, 2002, at an average interest rate of 2.6%. Debt outstanding under this program is generally borrowed for seven to 90 day periods, and may be borrowed up to 365 days, at prevailing commercial paper market rates. EFFECTS OF CHANGES IN FOREIGN CURRENCY RATES In the October 2001 Anderson acquisition, Devon's subsidiary assumed $400 million of long-term debt which is denominated in U.S. dollars. This debt matures in 2011. Changes in the exchange rate between the U.S. dollar and the Canadian dollar from October 15, when Devon acquired Anderson, to the dates of repayment will increase or decrease the expected amount of Canadian dollars eventually required to repay the debt. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. Because of the variability of the exchange rate, it is not possible to estimate the effect which will be recorded in 2002. However, for every $0.01 change in the exchange rate, Devon will record either revenue or expense of approximately $9 million Canadian dollars. The resulting revenue or expense in U.S. dollars will depend on the currency exchange rate in effect throughout the year. With the devaluation of the Argentine peso in January 2002, changes in the exchange rate between the U.S. dollar and the Argentine peso will also result in gains or losses for the period in which the exchange rate changes. The functional currency of Devon's Argentine subsidiary is the U.S. dollar. As a result, changes in the exchange rate between the U.S. dollar and the Argentine peso will increase or decrease the expected amount of Argentine pesos eventually collected or paid for transactions that are settled in pesos. Because of the variability of the exchange rate, it is not possible to estimate the effect which will be recorded in 2002. The resulting revenue or expense in U.S. dollars will depend on the currency exchange rate in effect throughout the year. 39
OTHER INCOME Devon's other income in 2002 is expected to be between $32 million and $36 million. INCOME TAXES Devon's financial income tax rate in 2002 will vary materially depending on the actual amount of financial pre-tax earnings. There are certain tax deductions and credits that will have a fixed impact on 2002's income tax expense regardless of the level of pre-tax earnings that are produced. Additionally, any gains or losses which may be recognized from the sale of the Disposition Properties has been excluded from these estimates of income taxes. Given these uncertainties, Devon estimates that its consolidated financial income tax rate in 2002 will be between 15% and 35%. The current income tax rate is expected to be between 5% and 15%. The deferred income tax rate is expected to be between 10% and 20%. Significant changes in estimated capital expenditures, production levels of oil, gas and NGLs, the prices of such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of the aforementioned tax deductions and credits on 2002's financial income tax rates. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Devon follows the full cost method of accounting for its oil and gas properties. Under the full cost method, Devon's net book value of oil and gas properties, less related deferred income taxes (the "costs to be recovered"), may not exceed a calculated "full cost ceiling." The ceiling limitation is the discounted estimated after-tax future net revenues from oil and gas properties plus the lower of cost or fair value of unproved properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The costs to be recovered are compared to the ceiling on a quarterly basis. If the costs to be recovered exceed the ceiling, the excess is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. Because of the volatile nature of oil and gas prices, it is not possible to predict whether Devon will incur a full cost writedown in future periods. Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than Devon's long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves. Devon recorded writedowns to its domestic and Canadian oil and gas properties as of December 31, 2001. The year-end 2001 prices used to calculate the ceiling were a NYMEX oil price of $19.84 per barrel, and a Henry Hub gas price of $2.65 per MMBtu. If oil or gas prices at the end of future quarters drop below these year-end 2001 prices, or if Devon reduces its estimates of proved reserve quantities, further writedowns would likely occur. Also, in January 40
2002, Devon closed its merger with Mitchell. The oil and gas properties acquired in this transaction were recorded at their estimated fair value. The fair values were based on Devon's estimates of future oil and gas prices, and these estimated prices were higher than the year-end 2001 market prices for oil and gas. This increases the likelihood that Devon could incur further writedowns of its domestic oil and gas properties in the future. PROPERTY ACQUISITIONS AND DIVESTITURES Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget," nor can it reasonably predict, the timing or size of such possible acquisitions, if any, other than the Mitchell acquisition closed on January 24, 2002. During 2002, Devon estimates that it will sell certain oil and gas properties (the "Disposition Properties") for between $1.2 billion and $1.5 billion. The Disposition Properties are predominantly those that are either outside of Devon's core operating areas or otherwise do not fit Devon's current strategic objectives. The Disposition Properties are located in the U.S., Canada and International areas. As of May 3, 2002, Devon has closed sales of Disposition Properties totaling $604 million in proceeds, and has signed agreements for an additional $598 million of transactions which are expected to close by the end of the second quarter of 2002. In addition, Devon has identified another $200 million to $300 million of Disposition Properties that could be sold in the second half of the year. The estimates of Devon's 2002 results previously set forth in this report exclude any results from the Disposition Properties. The Disposition Properties' actual contribution to Devon's 2002 operating results will depend upon when the transactions to sell the Disposition Properties are actually closed. The following table presents Devon's estimates of the Disposition Properties' quarterly operating results. For those transactions that are currently under contract but not yet closed, the following table assumes that such transactions will close on June 30, 2002. The table does not include the $200 to $300 million of various Disposition Properties that, if sold, are not expected to close until the second half of 2002. The following table includes production and expense estimates from International Disposition Properties. However, when these properties are ultimately sold, the financial presentation of the related operating results will differ. Pursuant to Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the International assets to be sold constitute a "component of an entity." As such, in the period in which such International properties are sold, the related operating results will be reported as discontinued operations. The prior periods' operating results related to such assets will also be reclassified and reported as discontinued operations. Therefore, upon the sale of these International Disposition Properties, the individual historical amounts for revenues and expenses of these properties will be netted and reported as discontinued operations. The results of the domestic and Canadian Disposition Properties will not be presented as discontinued operations due to significant continuing operations in the United States and Canada. 41
<Table> <Caption> EXPECTED RANGES -------------------------------- 1ST QUARTER 2ND QUARTER 2002 2002 ----------- ----------- <S> <C> <C> OIL (MMBbls) United States 1.5 1.4 to 1.6 Canada 0.8 0.2 to 0.3 International 1.7 0.9 to 1.0 Total 4.0 2.5 to 2.9 GAS (Bcf) United States 11 11 to 12 Canada 4 1 to 2 International 2 1 to 2 Total 17 13 to 16 NGLS (MMBbls) United States 0.4 0.1 to 0.2 Canada 0.1 0 to 0.1 International -- -- Total 0.5 0.1 to 0.3 LEASE OPERATING EXPENSES (IN MILLIONS) United States $ 20 $ 21 to 22 Canada 10 2 to 3 International 12 8 to 9 Total 42 31 to 34 TRANSPORTATION COSTS (IN MILLIONS) United States $ 1 $ 0 to 1 Canada 1 0 to 1 International -- -- Total 2 1 to 2 DD&A (IN MILLIONS) United States $ 24 $ 23 to 25 Canada 9 3 to 4 International 8 5 to 6 Total 41 31 to 35 </Table> Additionally, the estimates of Devon's 2002 results previously set forth in this report exclude the following oil and gas costless price collars which were entered into at the request of the expected purchaser of the Disposition Properties located in the United States. If this sale is consummated, these collars will transfer to the purchaser on the closing date. If this sale is not completed, Devon will retain these price collars. The oil collar is for 13,000 barrels per day from May 2002 through December 2002. The collar has a 42
floor and ceiling price per barrel of $24.00 and $26.80, respectively. The floor and ceiling prices are based on the NYMEX price. The gas collar is for 65,000 MMBtu per day from May 2002 through December 2002. The collar has a floor and ceiling price per MMBtu of $3.25 and $3.60, respectively. The prices on the gas collar have been adjusted to a NYMEX-based price, using Devon's estimate of 2002 differentials between NYMEX and the specific regional index upon which the collar is based. YEAR 2002 POTENTIAL CAPITAL EXPENDITURES AND OTHER CASH USES CAPITAL EXPENDITURES Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget", nor can it reasonably predict, the timing or size of such possible acquisitions, if any, other than the Mitchell acquisition. Devon's capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should actual prices differ materially from Devon's expectations for its future production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2002 capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon's estimates. Given the limitations discussed, the company expects its 2002 capital expenditures for drilling and development efforts, plus related facilities, to total between $1.3 billion and $1.5 billion. These amounts include between $495 million and $595 million for drilling and facilities costs related to reserves classified as proved as of year-end 2001. In addition, these amounts include between $530 million and $600 million for other low risk/reward projects and between $300 million and $350 million for new, higher risk/reward projects. Low risk/reward projects include development drilling that does not offset currently productive units and for which there is not a certainty of continued production from a known productive formation. Higher risk/reward projects include exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs. The following table shows expected drilling and facilities expenditures by geographic area. <Table> <Caption> DRILLING AND PRODUCTION FACILITIES EXPENDITURES ------------------------------------------------------------------------ UNITED STATES CANADA INTERNATIONAL TOTAL ------------ ------------- ------------- ----------------- ($ in millions) <S> <C> <C> <C> <C> Related to Proved Reserves $ 435 - $495 $ 15 - $ 35 $ 45 - $ 65 $ 495 - $ 595 Lower Risk/Reward Projects $ 275 - $305 $ 255 - $ 285 $ 0 - $ 10 $ 530 - $ 600 Higher Risk/Reward Projects $ 70 - $ 80 $ 210 - $ 240 $ 20 - $ 30 $ 300 - $ 350 ------------ ------------- ------------ ----------------- Total $ 780 - $880 $ 480 - $ 560 $ 65 - $ 105 $ 1,325 - $ 1,545 ============ ============= ============ ================= </Table> In addition to the above expenditures for drilling and development, Devon expects to spend between $135 million and $165 million on its marketing and midstream assets, which include its oil pipelines, gas processing plants, CO2 removal facilities and gas transport pipelines. Devon also expects to capitalize between $85 million and $105 million of G&A expenses in accordance with the full cost method of accounting. Devon also expects to pay between $20 43
million and $30 million for plugging and abandonment charges, and to spend between $15 million and $25 million for other non-oil and gas property fixed assets. OTHER CASH USES Devon's management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.05 per share quarterly dividend rate and 156 million shares of common stock outstanding after completion of the Mitchell acquisition, 2002 dividends are expected to approximate $31 million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay $10 million of dividends in 2002. IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants. The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation for settlement. The initial measurement of the asset retirement obligation is to be fair value, defined as "the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale." Devon expects that it will use a valuation technique such as expected present value to estimate fair value. The asset retirement cost equal to the fair value of the retirement obligation is to be capitalized as part of the cost of the related long-lived asset and allocated to expense using a systematic and rational method. Devon will be required to adopt SFAS No. 143 effective January 1, 2003 using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. Devon currently records estimated costs of dismantlement, removal, site reclamation, and other similar activities as part of depreciation, depletion, and amortization and does not record a separate liability for such amounts. Devon has not completed the assessment of the impact that adoption of SFAS No. 143 will have on its consolidated financial statements. However, Devon expects the amounts for capitalized oil and gas property costs and asset retirement obligations will increase. The FASB issued Statement No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, on April 30, 2002. Statement No. 145 rescinds Statement No. 4, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. Upon adoption of Statement No. 145, Devon will be required to apply the criteria in APB 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 (Opinion No. 30), in determining the classification of gains 44
and losses resulting from the extinguishment of debt. Based on that criteria, Devon does not expect to classify material gains and losses from early extinguishments of debt as extraordinary items in the future as was reported in the past. Additionally, Statement No. 145 amends Statement No. 13 to require that certain lease modifications that have economic effects similar to sale-leaseback transactions be accounted for in the same manner as sale-leaseback transactions. Statement No. 145 will be effective for fiscal years beginning after May 15, 2002, and upon adoption, Devon must reclassify prior period items that do not meet the extraordinary item classification criteria in Opinion No. 30. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information included in "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of Devon's 2001 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of Devon's potential exposure to market risks, including commodity price risk, interest rate risk and foreign currency risk. As of March 31, 2002, there have been no material changes in Devon's market risk exposure from that disclosed in the 2001 Form 10-K. 45
PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS None ITEM 2. CHANGES IN SECURITIES None ITEM 3. DEFAULTS UPON SENIOR SECURITIES None ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (a) Devon's special meeting of stockholders was held in Oklahoma City, Oklahoma at 10:00 a.m. local time, on Thursday January 24, 2002. (b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. (c) Out of a total of 126,092,673 shares of Devon's common stock outstanding and entitled to vote, 82,282,138 shares were present at the meeting in person or by proxy, representing approximately 65 percent of the total outstanding. The only matter voted upon at the meeting was the approval of the Amended and Restated Agreement and Plan of Merger, dated August 13, 2001, among Devon, Devon NewCo Corporation, Devon Holdco Corporation, Devon Merger Corporation, Mitchell Merger Corporation and Mitchell Energy & Development Corp. and the transactions that it contemplates. The results of the vote taken at such meeting was as follows: For 80,152,181 Against 1,408,920 Abstain 721,037 ITEM 5. OTHER INFORMATION None 46
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits required by Item 601 of Regulation S-K are as follows: None (b) Reports on Form 8-K: Filing Date Contents ----------- -------- January 18, 2002 Documents filed pursuant to Rule 425 of Securities Act of 1933 January 29, 2002 Year-end 2001 oil and gas reserves and various gas hedging instruments entered into in January 2002 February 6, 2002 Press release announcing 2001 results April 9, 2002 Exhibits related to Registration Statement on Form S-3 (File No. 333-83156) relating to an aggregate $1.5 billion of securities. 47
SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. DEVON ENERGY CORPORATION Date: May 15, 2002 /s/ Danny J. Heatly ----------------------------- Danny J. Heatly Vice President - Accounting 48