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 September 30, 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 $.10, as of October 31, 2002, was 156,666,000. 1 of 56 total pages (Exhibit Index is found at page 50) 1
DEVON ENERGY CORPORATION Index to Form 10-Q Quarterly Report to the Securities and Exchange Commission <Table> <Caption> Page No. -------- <S> <C> Part I. Financial Information Item 1. Consolidated Financial Statements Consolidated Balance Sheets, September 30, 2002 (Unaudited) 4 and December 31, 2001 Consolidated Statements of Operations (Unaudited) 5 for the Three Months and Nine Months Ended September 30, 2002 and 2001 Consolidated Statements of Comprehensive Earnings 7 (Unaudited) for the Three Months and Nine Months Ended September 30, 2002 and 2001 Consolidated Statements of Cash Flows (Unaudited) 8 for the Nine Months Ended September 30, 2002 and 2001 Notes to Consolidated Financial Statements 9 Item 2. Management's Discussion and Analysis of Financial 28 Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk 44 Item 4. Controls and Procedures 44 Part II. Other Information Item 6. Exhibits and Reports on Form 8-K 46 </Table> DEFINITIONS As used in this document: "Mcf" means thousand cubic feet "Bcf" means billion cubic feet "Bbl" means barrel "MBbls" means thousand barrels "MMBbls" means million barrels "Boe" means equivalent barrels of oil "MMBoe" means million equivalent barrels of oil "Oil" includes crude oil and condensate "NGLs" means natural gas liquids "C$" means Canadian dollar 2
DEVON ENERGY CORPORATION PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 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> SEPTEMBER 30, DECEMBER 31, 2002 2001 --------------- --------------- (UNAUDITED) <S> <C> <C> ASSETS Current assets: Cash and cash equivalents $ 88 183 Accounts receivable 569 494 Inventories 33 23 Fair value of financial instruments 5 195 Deferred income taxes 2 -- Income taxes receivable -- 68 Assets of discontinued operations 96 335 Investments and other current assets 43 45 --------------- --------------- Total current assets 836 1,343 --------------- --------------- Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($2,443 and $1,938 excluded from amortization in 2002 and 2001, respectively) 18,423 14,944 Less accumulated depreciation, depletion and amortization 7,624 6,170 --------------- --------------- 10,799 8,774 Investment in ChevronTexaco Corporation common stock, at fair value 491 636 Fair value of financial instruments 2 31 Goodwill 3,590 2,206 Other assets 299 194 --------------- --------------- Total assets $ 16,017 13,184 =============== =============== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade 405 432 Revenues and royalties due to others 201 170 Income taxes payable 68 16 Accrued interest payable 77 102 Merger related expenses payable 26 7 Fair value of financial instruments 87 15 Deferred income taxes -- 57 Liabilities of discontinued operations 6 66 Accrued expenses and other current liabilities 119 72 --------------- --------------- Total current liabilities 989 937 --------------- --------------- Other liabilities 285 172 Debentures exchangeable into shares of ChevronTexaco Corporation common stock 659 649 Other long-term debt 6,987 5,940 Deferred revenue -- 51 Fair value of financial instruments 35 45 Deferred income taxes 2,529 2,131 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 160,245,000 in 2002 and 129,886,000 in 2001 16 13 Additional paid-in capital 5,165 3,610 Accumulated deficit (158) (147) Accumulated other comprehensive loss (301) (28) Treasury stock, at cost: 3,754,000 shares in 2002 and 2001 (190) (190) --------------- --------------- Total stockholders' equity 4,533 3,259 --------------- --------------- Total liabilities and stockholders' equity $ 16,017 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 NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ------------------------ 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (UNAUDITED) REVENUES <S> <C> <C> <C> <C> Oil sales $ 218 191 692 595 Gas sales 480 303 1,508 1,465 Natural gas liquids sales 69 30 196 94 Marketing and midstream revenues 265 12 692 47 ---------- ---------- ---------- ---------- Total revenues 1,032 536 3,088 2,201 ---------- ---------- ---------- ---------- PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 152 111 470 322 Transportation costs 39 16 115 52 Production taxes 25 21 80 94 Marketing and midstream costs and expenses 212 3 559 31 Depreciation, depletion and amortization of property and equipment 283 195 918 544 Amortization of goodwill -- 8 -- 25 General and administrative expenses 47 28 151 78 Reduction of carrying value of oil and gas properties -- 10 651 87 ---------- ---------- ---------- ---------- Total costs and expenses 758 392 2,944 1,233 ---------- ---------- ---------- ---------- Earnings from operations 274 144 144 968 OTHER INCOME (EXPENSES) Interest expense (130) (36) (402) (105) Effects of changes in foreign currency exchange rates (17) -- -- -- Change in fair value of financial instruments 21 2 28 (5) Other income 2 5 23 25 ---------- ---------- ---------- ---------- Net other expenses (124) (29) (351) (85) ---------- ---------- ---------- ---------- Earnings (loss) from continuing operations before income tax expense (benefit) and cumulative effect of change in accounting principle 150 115 (207) 883 INCOME TAX EXPENSE (BENEFIT) Current 36 (35) 122 100 Deferred 2 80 (293) 255 ---------- ---------- ---------- ---------- Total income tax expense (benefit) 38 45 (171) 355 ---------- ---------- ---------- ---------- Earnings (loss) from continuing operations before cumulative effect of change in accounting principle 112 70 (36) 528 DISCONTINUED OPERATIONS Results of discontinued operations before income taxes (including (loss) gain on disposal of ($55 million) and $43 million in the three-month and nine-month periods ended September 30, 2002, respectively) (48) 25 63 74 Total income tax expense 2 10 7 30 ---------- ---------- ---------- ---------- Net results of discontinued operations (50) 15 56 44 ---------- ---------- ---------- ---------- Earnings before cumulative effect of change in accounting principle 62 85 20 572 Cumulative effect of change in accounting principle, net of income tax expense of $32 million -- -- -- 49 ---------- ---------- ---------- ---------- Net earnings 62 85 20 621 Preferred stock dividends 2 2 7 7 ---------- ---------- ---------- ---------- Net earnings applicable to common shareholders $ 60 83 13 614 ========== ========== ========== ========== </Table> See accompanying notes to consolidated financial statements. 5
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) (CONTINUED) <Table> <Caption> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ------------------------ 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (UNAUDITED) <S> <C> <C> <C> <C> Basic earnings (loss) per average common share outstanding: Earnings (loss) from continuing operations $ 0.70 0.53 (0.28) 4.06 Earnings (loss) from discontinued operations (0.32) 0.12 0.36 0.35 Cumulative effect of change in accounting principle -- -- -- 0.38 ---------- ---------- ---------- ---------- Net earnings $ 0.38 0.65 0.08 4.79 ========== ========== ========== ========== Diluted earnings (loss) per average common share outstanding: Earnings (loss) from continuing operations 0.68 0.53 (0.28) 3.94 Earnings (loss) from discontinued operations (0.31) 0.11 0.36 0.33 Cumulative effect of change in accounting principle -- -- -- 0.36 ---------- ---------- ---------- ---------- Net earnings $ 0.37 0.64 0.08 4.63 ========== ========== ========== ========== Weighted average common shares outstanding-basic 156 126 154 128 Weighted average common shares outstanding-diluted 158 131 154 134 </Table> See accompanying notes to consolidated financial statements. 6
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (IN MILLIONS) <Table> <Caption> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------ ------------------------ 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (UNAUDITED) <S> <C> <C> <C> <C> Net earnings $ 62 85 20 621 Other comprehensive earnings (loss), net of tax: Foreign currency translation adjustments (167) (18) 33 (21) Cumulative effect of change in accounting principle -- -- -- (37) Adjustment to reclassify derivative (gains) losses into oil and gas sales (10) (8) (51) 7 Change in fair value of outstanding hedging positions (43) 64 (167) 105 Unrealized gains (losses) on marketable securities (83) (25) (88) 2 ---------- ---------- ---------- ---------- Comprehensive earnings (loss) $ (241) 98 (253) 677 ========== ========== ========== ========== </Table> See accompanying notes to consolidated financial statements. 7
DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN MILLIONS) <Table> <Caption> NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2002 2001 ------------- -------------- (UNAUDITED) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net earnings (loss) from continuing operations $ (36) 528 Adjustments to reconcile earnings (loss) from continuing operations to net cash provided by operating activities: Depreciation, depletion and amortization of property and equipment 918 544 Amortization of goodwill -- 25 Reduction of carrying value of oil and gas properties 651 87 Amortization of discounts on other long-term debt, net 24 18 Change in fair value of derivative instruments (28) 5 Deferred income tax expense (benefit) (293) 255 Operating cash flows of discontinued operations (39) 50 Gain on sale of assets (1) -- Other (6) 2 Changes in assets and liabilities, net of effects of acquisitions of businesses: (Increase) decrease in: Accounts receivable (12) 106 Inventories 6 4 Income tax receivable -- 14 Other assets (21) (29) (Decrease) increase in: Accounts payable (84) 28 Income taxes payable 161 (55) Accrued expenses and other current liabilities (9) (52) Deferred revenue (44) (49) Long-term other liabilities (11) (23) ------------ ------------ Net cash provided by operating activities 1,176 1,458 ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of property and equipment 1,312 41 Capital expenditures, including business acquisitions (3,049) (1,294) Discontinued operations (8) (57) Increase in other assets (4) -- ------------ ------------ Net cash used in investing activities (1,749) (1,310) ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings of long-term debt, net of issuance costs 5,506 1,272 Principal payments on long-term debt (5,018) (1,264) Issuance of common stock, net of issuance costs 19 31 Repurchase of common stock -- (190) Dividends paid on common stock (23) (20) Dividends paid on preferred stock (7) (7) ------------ ------------ Net cash provided by (used in) financing activities 477 (178) ------------ ------------ Effect of exchange rate changes on cash 1 (1) ------------ ------------ Net decrease in cash and cash equivalents (95) (31) Cash and cash equivalents at beginning of period 183 194 ------------ ------------ Cash and cash equivalents at end of period $ 88 163 ============ ============ </Table> See accompanying notes to consolidated financial statements. 8
DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The accompanying consolidated financial statements and notes thereto of Devon Energy Corporation ("Devon") have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain 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 Current Report on Form 8-K filed October 3, 2002. 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 September 30, 2002, and the results of their operations and their cash flows for the three-month and nine-month periods ended September 30, 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 are subject to change. 9
<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 17, 2001, Devon completed its acquisition of all the common shares of Anderson Exploration Ltd. ("Anderson"). 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 nine-month periods ended September 30, 2002 and 2001. The information for the nine-month periods ended September 30, 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. 10
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. - Devon's historical results of operations for the nine-month period ended September 30, 2001 include $25 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 is 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 or the Mitchell merger. 11
<Table> <Caption> PRO FORMA INFORMATION NINE MONTHS ENDED SEPTEMBER 30 -------------------------------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS AND PRODUCTION VOLUMES) 2002 2001 -------------- -------------- <S> <C> <C> REVENUES Oil sales $ 694 852 Gas sales 1,530 2,624 Natural gas liquids sales 201 247 Marketing and midstream revenues 762 1,002 -------------- -------------- Total revenues 3,187 4,725 -------------- -------------- PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 474 536 Transportation costs 118 113 Production taxes 81 121 Marketing and midstream costs and expenses 624 880 Depreciation, depletion and amortization of property and 937 993 equipment Amortization of goodwill -- 25 General and administrative expenses 156 155 Reduction of carrying value of oil and gas properties 651 87 -------------- -------------- Total production and operating costs and expenses 3,041 2,910 -------------- -------------- Earnings from operations 146 1,815 OTHER INCOME (EXPENSES) Interest expense (403) (365) Effects of changes in foreign currency exchange rates -- (15) Change in fair value of financial instruments 28 (19) Other income 23 22 -------------- -------------- Net other expenses (352) (377) -------------- -------------- Earnings (loss) from continuing operations before income tax expense (benefit) and cumulative effect of change in accounting principle (206) 1,438 INCOME TAX EXPENSE (BENEFIT) Current 122 140 Deferred (292) 415 -------------- -------------- Total income tax expense (benefit) (170) 555 -------------- -------------- Earnings (loss) from continuing operations before cumulative effect of change in accounting principle (36) 883 DISCONTINUED OPERATIONS Results of discontinued operations before income taxes (including gain on disposal of $43 million in 2002) 63 74 Total income tax expense 7 30 -------------- -------------- Net results of discontinued operations 56 44 -------------- -------------- Earnings before cumulative effect of change in accounting principle 20 927 Cumulative effect of change in accounting principle -- 49 -------------- -------------- Net earnings 20 976 Preferred stock dividends 7 7 -------------- -------------- Net earnings applicable to common stockholders $ 13 969 ============== ============== </Table> 12
<Table> <Caption> PRO FORMA INFORMATION NINE MONTHS ENDED SEPTEMBER 30 ------------------------------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS AND PRODUCTION VOLUMES) 2002 2001 ------------- ------------- <S> <C> <C> Basic earnings (loss) per average common share outstanding: Earnings (loss) from continuing operations $ (0.28) 5.54 Earnings from discontinued operations 0.36 0.28 Cumulative effect of change in accounting principle -- 0.31 ------------ ------------ Net earnings $ 0.08 6.13 ============ ============ Diluted earnings (loss) per average common share outstanding: Earnings (loss) from continuing operations (0.28) 5.38 Earnings from discontinued operations 0.36 0.27 Cumulative effect of change in accounting principle -- 0.30 ------------ ------------ Net earnings $ 0.08 5.95 ============ ============ Weighted average common shares outstanding - basic 156 158 Weighted average common shares outstanding - diluted 156 164 Production volumes: Oil (MMBbls) 32 37 Gas (Bcf) 586 592 NGLs (MMBbls) 16 13 MMBoe 146 149 </Table> 3. LONG-TERM DEBT $3 Billion Term Loan Credit Facility Prior to December 31, 2001, Devon used proceeds of $1 billion of a $3 billion term loan credit 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 September 30, 2002, $1.9 billion of the balance outstanding was retired. The primary sources of the repayments were the issuance of $1 billion of debt securities, of which $0.8 billion was used to pay down debt, and $1.1 billion from the sale of certain oil and gas properties. As of September 30, 2002, the balance outstanding under the term loan credit facility was $1.1 billion at an average rate of 2.8%. Debt Securities On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15, 2032. The net proceeds received, after discounts and issuance costs, were $986 million. The debt securities are unsecured and unsubordinated obligations of Devon. The net proceeds were partially used to pay down $820 million on Devon's $3 billion term loan credit facility. The remaining $166 million of net proceeds was used in June 2002 to partially fund the early extinguishment of $175 million of 8.75% senior notes due June 15, 2007. The notes were redeemed at 104.375% of principal, or approximately $183 million. Commercial Paper As of September 30, 2002, Devon had $78 million of borrowings under its commercial paper program at an average rate of 2.3%. Because Devon has the intent and ability to refinance the balance due with borrowings under its credit facilities, the $78 million outstanding under the commercial paper program was classified as long-term debt on the September 30, 2002 consolidated balance sheet. 13
Credit Facilities Devon has $1 billion of unsecured long-term credit facilities (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The $725 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $525 million. On June 7, 2002, Devon renewed the $525 million Tranche B facility and its $275 million Canadian facility. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until June 5, 2003 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. On June 6, 2003, at the end of the Tranche B Revolving Period, Devon may convert the then outstanding balance under the Tranche B facility to a two-year term loan by paying the Agent a fee of 12.5 basis points. The applicable borrowing rate would be at LIBOR plus 125 basis points. On September 30, 2002, there were no borrowings outstanding under the $725 million U.S. Facility. The available capacity under the U.S. Facility as of September 30, 2002, net of commercial paper borrowings and outstanding letters of credit, was $623 million. Devon may borrow funds under the $275 million Canadian Facility until June 5, 2003 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semiannual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. On September 30, 2002, there were no borrowings under the $275 million Canadian facility. Under the terms of the Credit Facilities, Devon has the right to reallocate up to $100 million of the unused Tranche B facility maximum credit amount to the Canadian Facility. Conversely, Devon also has the right to reallocate up to $100 million of unused Canadian Facility maximum credit amount to the Tranche B Facility. Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $1.4 million that is payable quarterly. 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 65%. 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 September 30, 2002, 14
Devon's ratio of total funded debt to total capitalization, as defined in its credit agreements, was 55.8%. Letter of Credit Facility On July 25, 2002, Devon renewed and increased its letter of credit and revolving bank facility ("LOC Facility") for its Canadian operations. This C$150 million LOC Facility will be used primarily by Devon's wholly-owned subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to issue letters of credit. As of September 30, 2002, C$105 million ($ 66 million converted to U.S. dollars using the September 30, 2002 exchange rate) of letters of credit were issued under the LOC Facility primarily for Canadian drilling commitments. 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 certain Canadian gas revenues that are 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 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 September 30, 2002, $82 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 the hedged oil and gas quantities. The maximum term over which Devon is hedging exposures to the variability of cash flows for commodity price risk is 27 months. Devon recorded in its statements of operations a gain of $21 million and $2 million in the third quarter of 2002 and 2001, respectively, and a gain of $28 million and a loss of $5 million in the nine-month periods ended September 30, 2002 and 2001, respectively, for the change in fair value of derivative instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that do qualify as hedges. Included in the three-month periods ended September 30, 2002 and 2001 are a net loss of $3 million and $1 million, respectively, related to such ineffectiveness. Included in the nine-month periods ended September 30, 2002 and 2001 are a net gain of $7 million and a net loss of $1 million, respectively, related to such ineffectiveness. These gains and losses are related to both (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 Assets (SFAS No. 142). 15
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. 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 completed its assessment of the fair value of its reporting units and compared such fair value to each reporting unit's carrying value, including goodwill, as of January 1, 2002. Based on this assessment, no transitional impairment of the carrying value of goodwill was required. As a result of the January 2002 Mitchell acquisition, goodwill increased $1.4 billion. 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 SEPTEMBER 30, 2002 2001 ------------ ------------ (IN MILLIONS, EXCEPT PER SHARE DATA) <S> <C> <C> Net earnings applicable to common shareholders, as reported $ 60 83 Add back amortization of goodwill -- 8 ------------ ------------ Net earnings applicable to common shareholders, as adjusted $ 60 91 ============ ============ Basic earnings per share: Net earnings applicable to common shareholders, as reported 0.38 0.65 Amortization of goodwill -- 0.06 ------------ ------------ Net earnings applicable to common shareholders, as adjusted $ 0.38 0.71 ============ ============ Diluted earnings per share: Net earnings applicable to common shareholders, as reported 0.37 0.64 Amortization of goodwill -- 0.06 ------------ ------------ Net earnings applicable to common shareholders, as adjusted $ 0.37 0.70 ============ ============ </Table> 16
<Table> <Caption> FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002 2001 ------------ ------------ (IN MILLIONS, EXCEPT PER SHARE DATA) <S> <C> <C> Net earnings applicable to common shareholders, as reported $ 13 614 Add back amortization of goodwill -- 25 ------------ ------------ Net earnings applicable to common shareholders, as adjusted $ 13 639 ============ ============ Basic earnings per share: Net earnings applicable to common shareholders, as reported 0.08 4.79 Amortization of goodwill -- 0.20 ------------ ------------ Net earnings applicable to common shareholders, as adjusted $ 0.08 4.99 ============ ============ Diluted earnings per share: Net earnings applicable to common shareholders, as reported 0.08 4.63 Amortization of goodwill -- 0.19 ------------ ------------ Net earnings applicable to common shareholders, as adjusted $ 0.08 4.82 ============ ============ </Table> 6. EARNINGS PER SHARE The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month periods ended September 30, 2002 and 2001 and the nine-month period ended September 30, 2001. The diluted earnings per share calculations for the nine-month period ended September 30, 2002 produce results that are anti-dilutive as a result of the loss on continuing operations. (The diluted calculation for the nine months ended September 30, 2002 increased the net earnings by $5 million and increased the common shares outstanding by 6 million shares.) Therefore, the diluted earnings per share amounts for the nine-month period ended September 30, 2002 reported in the accompanying consolidated statements of operations are the same as the basic earnings per share amounts. <Table> <Caption> NET EARNINGS NET APPLICABLE COMMON EARNINGS TO COMMON SHARES PER STOCKHOLDERS OUTSTANDING SHARE ------------ ----------- ----------- (IN MILLIONS, EXCEPT PER SHARE DATA) THREE MONTHS ENDED SEPTEMBER 30, 2002: <S> <C> <C> <C> Basic earnings per share $ 60 156 $ 0.38 ========== Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options -- 2 ---------- ---------- Diluted earnings per share $ 60 158 $ 0.37 ========== ========== ========== </Table> 17
<Table> <Caption> NET EARNINGS NET APPLICABLE COMMON EARNINGS TO COMMON SHARES PER STOCKHOLDERS OUTSTANDING SHARE ------------ ------------ ------------ (IN MILLIONS, EXCEPT PER SHARE DATA) <S> <C> <C> <C> THREE MONTHS ENDED SEPTEMBER 30, 2001: Basic earnings per share 83 126 0.65 ============ 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) 2 4 Potential common shares issuable upon the exercise of outstanding stock options -- 1 ------------ ------------ Diluted earnings per share $ 85 131 $ 0.64 ============ ============ ============ NINE MONTHS ENDED SEPTEMBER 30, 2001: Basic earnings per share 614 128 4.79 ============ Dilutive effect of: Potential common shares issuable upon the conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $4) 7 4 Potential common shares issuable upon the exercise of outstanding stock options -- 2 ------------ ------------ Diluted earnings per share $ 621 134 $ 4.63 ============ ============ ============ </Table> The senior convertible debentures were not included in the dilution calculation for the three-month period ended September 30, 2002, because the inclusion was anti-dilutive. Options to purchase approximately 3.3 million shares of Devon's common stock with exercise prices ranging from $44.60 per share to $89.66 per share (with a weighted average price of $53.89 per share) were outstanding at September 30, 2002, but were not included in the computation of diluted earnings per share for the third quarter of 2002 because the options' exercise prices exceeded the average market price of Devon's common stock during the period. Similarly, options to purchase approximately 3.0 million shares of Devon's common stock with exercise prices ranging from $45.49 per share to $89.66 per share (with a weighted average price of $55.58 per share) were excluded from the diluted earnings per share calculation for the third quarter of 2001. The excluded options for the 2002 period expire between November 30, 2002 and May 16, 2012. All options to purchase Devon common stock were excluded from the diluted earnings per share calculations for the first nine months of 2002 because of the anti-dilutive effect of such 18
options. Options to purchase approximately 1.1 million shares of Devon's common stock with exercise prices ranging from $52.39 per share to $89.66 per share (with a weighted average price of $63.44 per share) were excluded from the diluted earnings per share calculation for the first nine months of 2001. 7. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Under the full cost method of accounting, the 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 cost of properties not subject to amortization. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely, and Devon does not include the effect of hedges in the calculation of the future net revenues. Therefore, the ceiling limitation is not necessarily indicative of the properties' fair value. 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. Based on oil and natural gas cash market prices as of June 30, 2002, Devon's Canadian costs to be recovered exceeded the related ceiling value by $371 million. This after-tax amount resulted in a pre-tax reduction of the carrying value of Devon's Canadian oil and gas properties of $651 million in the second quarter of 2002. This reduction was the result of a sharp drop in Canadian gas prices during the last half of June 2002. The June 30, 2002, reference prices used in the Canadian ceiling calculation, expressed in Canadian dollars based on an exchange ratio of $0.6585, were a NYMEX price of C$40.79 per barrel of oil and an AECO price of C$2.17 per Mcf of gas. The cash market prices of natural gas increased during the month of July 2002 prior to Devon's release of its second quarter results, but the increase was not sufficient to offset the entire reduction calculated as of June 30. 8. DISCONTINUED OPERATIONS Effective January 1, 2002, Devon was required to adopt SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes both SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions of 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, for the disposal of a segment of a business (as previously defined in that Opinion). On April 18, 2002, Devon, sold its Indonesian operations to PetroChina Company Limited for total cash consideration of $250 million. In accordance with SFAS No. 144, Devon has reclassified the assets, liabilities and results of its Indonesian operations, which were included in Devon's International segment, as discontinued operations for each of the periods presented. 19
On August 13, 2002, Devon announced that it had entered into an agreement to sell its operations in Argentina to Petroleo Brasileiro S.A. - Petrobras. The purchase price was approximately $90 million. Devon completed this sale in October 2002. In accordance with SFAS No. 144, Devon has recognized a loss in the third quarter of 2002 of $55 million from the divestiture, and has reclassified the assets, liabilities and results of its Argentine operations, which were included in Devon's International segment, as discontinued operations for each of the periods presented. The following tables include the major classes of assets and liabilities and the revenues that were reclassified. <Table> <Caption> SEPTEMBER 30, DECEMBER 31, 2002 2001 --------------- --------------- (IN MILLIONS) <S> <C> <C> MAJOR CLASSES OF ASSETS AND LIABILITIES Cash $ 16 10 Accounts receivable 6 43 Inventories 3 18 Other current assets -- 2 Property and equipment, net of accumulated depreciation, depletion and amortization 53 254 Other assets 18 8 --------------- --------------- Total assets $ 96 335 =============== =============== Accounts payable - trade 3 33 Income taxes payable 2 14 Accrued expense 1 1 Other liabilities -- 7 Deferred income taxes -- 11 --------------- --------------- Total liabilities $ 6 66 =============== =============== </Table> <Table> <Caption> FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------- --------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> REVENUES Oil sales $ 14 43 61 128 Gas sales 2 4 6 10 NGL sales -- -- 1 -- ------------ ------------ ------------ ------------ Total revenues $ 16 47 68 138 ============ ============ ============ ============ </Table> 9. SUPPLEMENTAL CASH FLOW INFORMATION Cash payments (refunds) for interest and income taxes in the first nine months of 2002 and 2001 are presented below: <Table> <Caption> FOR THE NINE MONTHS ENDED SEPTEMBER 30, ------------------------- 2002 2001 ---------- --------- (IN MILLIONS) <S> <C> <C> Interest paid $ 427 96 Income taxes paid (refunded) (41) 157 </Table> 20
The 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 --------- Assets acquired with non-cash consideration $ 3,150 ========= </Table> 10. SEGMENT INFORMATION Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three 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 and marketing and midstream activities. Following is certain financial information regarding Devon's segments. The revenues reported are all from external customers. <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ------------ ------------ ------------ ------------ (IN MILLIONS) AS OF SEPTEMBER 30, 2002: <S> <C> <C> <C> <C> Current assets $ 440 198 198 836 Property and equipment, net of accumulated depreciation, depletion and amortization 6,836 3,459 504 10,799 Investment in ChevronTexaco Corporation common stock 491 -- -- 491 Goodwill, net of amortization 1,583 1,938 69 3,590 Other assets 267 34 -- 301 ------------ ------------ ------------ ------------ Total assets $ 9,617 5,629 771 16,017 ============ ============ ============ ============ Current liabilities 421 438 130 989 Other liabilities 270 9 6 285 Debentures exchangeable into shares of ChevronTexaco Corporation common stock 659 -- -- 659 Other long-term debt 2,873 4,114 -- 6,987 Fair value of derivative instruments 27 8 -- 35 Deferred income taxes 1,415 1,072 42 2,529 Stockholders' equity 3,952 (12) 593 4,533 ------------ ------------ ------------ ------------ Total liabilities and stockholders' equity $ 9,617 5,629 771 16,017 ============ ============ ============ ============ </Table> 21
10. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> THREE MONTHS ENDED SEPTEMBER 30, 2002: REVENUES Oil sales $ 119 83 16 218 Gas sales 328 152 -- 480 Natural gas liquids sales 48 21 -- 69 Marketing and midstream revenues 262 3 -- 265 ------------ ------------ ------------ ------------ Total revenues 757 259 16 1,032 ------------ ------------ ------------ ------------ PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 85 64 3 152 Transportation costs 25 14 -- 39 Production taxes 23 2 -- 25 Marketing and midstream costs and expenses 211 1 -- 212 Depreciation, depletion and amortization of property and equipment 200 82 1 283 General and administrative expenses 36 9 2 47 ------------ ------------ ------------ ------------ Total production and operating costs and expenses 580 172 6 758 ------------ ------------ ------------ ------------ Earnings from operations 177 87 10 274 OTHER INCOME (EXPENSES) Interest expense (57) (72) (1) (130) Effects of changes in foreign currency exchange rates -- (17) -- (17) Change in fair value of financial instruments 27 (6) -- 21 Other income (2) 3 1 2 ------------ ------------ ------------ ------------ Net other expenses (32) (92) -- (124) ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations before income tax expense 145 (5) 10 150 INCOME TAX EXPENSE Current 32 2 2 36 Deferred 1 -- 1 2 ------------ ------------ ------------ ------------ Total income tax expense 33 2 3 38 ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations 112 (7) 7 112 DISCONTINUED OPERATIONS Results of discontinued operations before income taxes -- -- (48) (48) Total income tax expense -- -- 2 2 ------------ ------------ ------------ ------------ Net results of discontinued operations -- -- (50) (50) ------------ ------------ ------------ ------------ Net earnings (loss) 112 (7) (43) 62 Preferred stock dividends 2 -- -- 2 ------------ ------------ ------------ ------------ Net earnings (loss) applicable to common shareholders $ 110 (7) (43) 60 ============ ============ ============ ============ Capital expenditures $ 325 129 30 484 ============ ============ ============ ============ </Table> 22
10. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> THREE MONTHS ENDED SEPTEMBER 30, 2001: REVENUES Oil sales $ 148 28 15 191 Gas sales 269 34 -- 303 Natural gas liquids sales 27 3 -- 30 Marketing and midstream revenues 10 2 -- 12 ------------ ------------ ------------ ------------ Total revenues 454 67 15 536 ------------ ------------ ------------ ------------ PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 90 17 4 111 Transportation costs 13 3 -- 16 Production taxes 20 1 -- 21 Marketing and midstream costs and expenses 3 -- -- 3 Depreciation, depletion and amortization of property and equipment 168 21 6 195 Amortization of goodwill 8 -- -- 8 General and administrative expenses 24 1 3 28 Reduction of carrying value of oil and gas properties -- -- 10 10 ------------ ------------ ------------ ------------ Total production and operating costs and expenses 326 43 23 392 ------------ ------------ ------------ ------------ Earnings (loss) from operations 128 24 (8) 144 OTHER INCOME (EXPENSES) Interest expense (35) (1) -- (36) Change in fair value of financial instruments 3 (1) -- 2 Other income (expense) -- -- 5 5 ------------ ------------ ------------ ------------ Net other income (expenses) (32) (2) 5 (29) ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations before income 96 22 (3) 115 tax expense (benefit) INCOME TAX EXPENSE (BENEFIT) Current (28) 1 (8) (35) Deferred 60 12 8 80 ------------ ------------ ------------ ------------ Total income tax expense (benefit) 32 13 -- 45 ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations 64 9 (3) 70 DISCONTINUED OPERATIONS Results of discontinued operations before income taxes -- -- 25 25 Total income tax expense -- -- 10 10 ------------ ------------ ------------ ------------ Net results of discontinued operations -- -- 15 15 ------------ ------------ ------------ ------------ Net earnings 64 9 12 85 Preferred stock dividends 2 -- -- 2 ------------ ------------ ------------ ------------ Net earnings applicable to common shareholders $ 62 9 12 83 ============ ============ ============ ============ Capital expenditures $ 277 44 -- 321 ============ ============ ============ ============ </Table> 23
10. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> NINE MONTHS ENDED SEPTEMBER 30, 2002: REVENUES Oil sales $ 397 255 40 692 Gas sales 1,008 500 -- 1,508 Natural gas liquids sales 134 62 -- 196 Marketing and midstream revenues 682 10 -- 692 ------------ ------------ ------------ ------------ Total revenues 2,221 827 40 3,088 ------------ ------------ ------------ ------------ PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 272 187 11 470 Transportation costs 73 42 -- 115 Production taxes 75 5 -- 80 Marketing and midstream costs and expenses 554 5 -- 559 Depreciation, depletion and amortization of property and equipment 624 290 4 918 General and administrative expenses 113 27 11 151 Reduction of carrying value of oil and gas properties -- 651 -- 651 ------------ ------------ ------------ ------------ Total production and operating costs and expenses 1,711 1,207 26 2,944 ------------ ------------ ------------ ------------ Earnings (loss) from operations 510 (380) 14 144 OTHER INCOME (EXPENSES) Interest expense (179) (220) (3) (402) Change in fair value of financial instruments 32 (4) -- 28 Other income 13 5 5 23 ------------ ------------ ------------ ------------ Net other income (expenses) (134) (219) 2 (351) ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations before income tax expense (benefit) 376 (599) 16 (207) INCOME TAX EXPENSE (BENEFIT) Current 106 11 5 122 Deferred (41) (256) 4 (293) ------------ ------------ ------------ ------------ Total income tax expense (benefit) 65 (245) 9 (171) ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations 311 (354) 7 (36) DISCONTINUED OPERATIONS Results of discontinued operations before income taxes -- -- 63 63 Total income tax expense -- -- 7 7 ------------ ------------ ------------ ------------ Net results of discontinued operations -- -- 56 56 ------------ ------------ ------------ ------------ Net earnings (loss) 311 (354) 63 20 Preferred stock dividends 7 -- -- 7 ------------ ------------ ------------ ------------ Net earnings (loss) applicable to common shareholders $ 304 (354) 63 13 ============ ============ ============ ============ Capital expenditures, including acquisitions of businesses $ 2,549 425 75 3,049 ============ ============ ============ ============ </Table> 24
10. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ------------ ------------ ------------ ------------ (IN MILLIONS) NINE MONTHS ENDED SEPTEMBER 30, 2001: REVENUES <S> <C> <C> <C> <C> Oil sales $ 459 85 51 595 Gas sales 1,300 165 -- 1,465 Natural gas liquids sales 82 12 -- 94 Marketing and midstream revenues 40 7 -- 47 ------------ ------------ ------------ ------------ Total revenues 1,881 269 51 2,201 ------------ ------------ ------------ ------------ PRODUCTION AND OPERATING COSTS AND EXPENSES Lease operating expenses 258 49 15 322 Transportation costs 43 9 -- 52 Production taxes 93 2 (1) 94 Marketing and midstream costs and expenses 28 3 -- 31 Depreciation, depletion and amortization of property and equipment 464 60 20 544 Amortization of goodwill 25 -- -- 25 General and administrative expenses 69 5 4 78 Reduction of carrying value of oil and gas properties -- -- 87 87 ------------ ------------ ------------ ------------ Total production and operating costs and expenses 980 128 125 1,233 ------------ ------------ ------------ ------------ Earnings (loss) from operations 901 141 (74) 968 OTHER INCOME (EXPENSES) Interest expense (100) (4) (1) (105) Change in fair value of financial instruments (4) (1) -- (5) Other income 20 (2) 7 25 ------------ ------------ ------------ ------------ Net other income (expenses) (84) (7) 6 (85) ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations before income tax expense (benefit) and cumulative effect of change in accounting principle 817 134 (68) 883 INCOME TAX EXPENSE (BENEFIT) Current 104 2 (6) 100 Deferred 201 57 (3) 255 ------------ ------------ ------------ ------------ Total income tax expense (benefit) 305 59 (9) 355 ------------ ------------ ------------ ------------ Earnings (loss) from continuing operations before cumulative effect of change in accounting principle 512 75 (59) 528 DISCONTINUED OPERATIONS Results of discontinued operations before income taxes -- -- 74 74 Total income tax expense -- -- 30 30 ------------ ------------ ------------ ------------ Net results of discontinued operations -- -- 44 44 ------------ ------------ ------------ ------------ Earnings (loss) before cumulative effect of change in accounting principle 512 75 (15) 572 Cumulative effect of change in accounting principle 49 -- -- 49 ------------ ------------ ------------ ------------ Net earnings (loss) 561 75 (15) 621 Preferred stock dividends 7 -- -- 7 ------------ ------------ ------------ ------------ Net earnings (loss) applicable to common shareholders $ 554 75 (15) 614 ============ ============ ============ ============ Capital expenditures, including acquisitions of businesses $ 1,074 154 66 1,294 ============ ============ ============ ============ </Table> 25
11. 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 in excess of recorded accruals. 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 material 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 1999 merger with PennzEnergy Company 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 September 30, 2002, Devon's consolidated balance sheet included $9 million of non-current accrued liabilities, reflected in "Other liabilities," related to these and other environmental remediation liabilities. 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 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 26
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. Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject. 12. 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 present value of expected cash outflows 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 includes estimated costs of dismantlement, removal, site reclamation, and other similar activities in the total costs that are subject to depreciation, depletion, and amortization. Devon does not record a separate asset or 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. 27
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- month and nine-month periods ended September 30, 2002, compared to the three-month and nine-month periods ended September 30, 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 Devon recorded net earnings for the third quarter of 2002 of $62 million, or $0.38 per share. This compares to net earnings of $85 million, or $0.65 per share for the third quarter of 2001. Net earnings for the first nine months of 2002 were $20 million, or $0.08 per share. This compares to net earnings for the first nine months of 2001 of $621 million, or $4.79 per share. The decrease in third quarter net earnings was due to the effect of the discontinued operations. The decrease in the first nine months' net earnings was due to a decline in oil, natural gas and NGL prices and increases in expenses, including a $651 million reduction of carrying value of Canadian oil and gas properties. These negative effects in both periods were partially offset by an increase in production from the Anderson and Mitchell acquisitions. Additionally, the nine month period ended September 30, 2002, benefited from a net gain from discontinued operations. 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 net proceeds received, after discounts and issuance costs, were $986 million. The debt securities are unsecured and unsubordinated obligations of Devon. The net proceeds were partially used to pay down $820 million on Devon's $3 billion term loan credit facility. The remaining $166 million of net proceeds was used in June 2002 to partially fund the early extinguishment of $175 million of 8.75% senior notes due June 15, 2007. The notes were redeemed at 104.375% of principal, or approximately $183 million. On June 7, 2002, Devon renewed the $800 million, 364-day portion of its unsecured long-term credit facilities (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). On July 25, 2002, Devon renewed and increased its letter of credit and revolving bank facility ("LOC Facility") for its Canadian operations. This C$150 million LOC Facility will be used primarily by Devon's wholly-owned subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to issue letters of credit. 28
RESULTS OF OPERATIONS Total revenues increased $495 million, or 92%, in the third quarter of 2002, and $887 million, or 40%, in the first nine months of 2002. This was the result of increases in oil, gas and NGL production and an increase in marketing and midstream revenue, partially offset by a decline in the combined average price of oil, gas and NGLs. The increases in production and marketing and midstream revenues were primarily the result of the Anderson and Mitchell acquisitions. Oil, gas and NGL revenues were up $243 million, or 46%, for the third quarter of 2002 compared to the third quarter of 2001, and were up $242 million, or 11%, for the first nine months of 2002 compared to the first nine months of 2001. The three-month and nine-month periods comparison 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 NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------------ ------------------------------------ 2002 2001 CHANGE 2002 2001 CHANGE ---------- ---------- ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MMBbls) 9 8 +13% 32 25 +28% Gas (Bcf) 185 111 +66% 576 327 +76% NGLs (MMBbls) 5 2 +150% 15 5 +200% Oil, Gas and NGLs (MMBoe)1 45 29 +55% 143 85 +68% AVERAGE PRICES Oil (Per Bbl) $ 23.72 22.36 +6% 21.39 23.25 -8% Gas (Per Mcf) 2.59 2.73 -5% 2.62 4.48 -42% NGLs (Per Bbl) 14.10 15.75 -11% 13.35 19.44 -31% Oil, Gas and NGLs (Per Boe)1 17.07 18.11 -6% 16.75 25.37 -34% ($'S IN MILLIONS) REVENUES Oil $ 218 191 +14% 692 595 +16% Gas 480 303 +58% 1,508 1,465 +3% NGLs 69 30 +130% 196 94 +109% ---------- ---------- ---------- ---------- Combined $ 767 524 +46% 2,396 2,154 +11% ========== ========== ========== ========== </Table> 29
<Table> <Caption> DOMESTIC --------------------------------------------------------------------------- THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------------ ------------------------------------ 2002 2001 CHANGE 2002 2001 CHANGE ---------- ---------- ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MMBbls) 6 7 -14% 19 20 -5% Gas (Bcf) 118 95 +24% 365 280 +30% NGLs (MMBbls) 4 2 +100% 11 5 +120% Oil, Gas and NGLs (MMBoe)(1) 30 25 +20% 91 72 +26% AVERAGE PRICES Oil (Per Bbl) $ 23.48 22.32 +5% 21.55 23.41 -8% Gas (Per Mcf) 2.77 2.82 -2% 2.76 4.63 -40% NGLs (Per Bbl) 12.98 15.24 -15% 12.68 18.69 -32% Oil, Gas and NGLs (Per Boe)(1) 17.39 18.29 -5% 17.13 26.01 -34% ($'S IN MILLIONS) REVENUES Oil $ 119 148 -19% 397 459 -13% Gas 328 269 +22% 1,008 1,300 -23% NGLs 48 27 +78% 134 82 +63% ---------- ---------- ---------- ---------- Combined $ 495 444 +11% 1,539 1,841 -16% ========== ========== ========== ========== </Table> <Table> <Caption> CANADA --------------------------------------------------------------------------- THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------------ ------------------------------------ 2002 2001 CHANGE 2002 2001 CHANGE ---------- ---------- ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MMBbls) 3 1 +200% 12 4 +200% Gas (Bcf) 67 16 +319% 211 47 +349% NGLs (MMBbls) 1 -- N/M 4 -- N/M Oil, Gas and NGLs (MMBoe)(1) 15 4 +275% 51 12 +325% AVERAGE PRICES Oil (Per Bbl) $ 24.07 21.95 +10% 20.98 21.75 -4% Gas (Per Mcf) 2.28 2.16 +5% 2.37 3.57 -34% NGLs (Per Bbl) 17.54 21.72 -19% 15.06 26.37 -43% Oil, Gas and NGLs (Per Boe)(1) 16.22 16.17 +0% 15.89 21.73 -27% ($'S IN MILLIONS) REVENUES Oil $ 83 28 +196% 255 85 +200% Gas 152 34 +347% 500 165 +203% NGLs 21 3 +600% 62 12 +416% ---------- ---------- ---------- ---------- Combined $ 256 65 +293% 817 262 +212% ========== ========== ========== ========== </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 NGL are affected by market and other factors in addition to relative energy content. 30
In addition to the volumes included in the prior tables for domestic and Canadian production, in the third quarter of 2002 and 2001, Devon also produced 651,000 and 631,000 barrels of oil, respectively, in its International division. The oil revenues generated by this production were $16 million and $15 million, respectively. In the first nine months of 2002 and 2001, Devon also produced 1,518,000 and 2,078,000 barrels of oil, respectively, in its International division. The oil revenues generated by this production were $40 million and $51 million, respectively. 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 and nine-month periods ended September 30, 2002 and 2001. <Table> <Caption> WITH HEDGES WITHOUT HEDGES --------------------------- --------------------------- THREE MONTHS ENDED THREE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, 2002 2001 2002 2001 ------------ ------------ ------------ ------------ <S> <C> <C> <C> <C> Oil (per Bbl) $ 23.72 22.36 $ 25.27 23.03 Gas (per Mcf) 2.59 2.73 2.46 2.61 NGLs (per Bbl) 14.10 15.75 14.10 15.75 Oil, Gas and NGLs (per Boe) 17.07 18.11 16.83 17.90 </Table> <Table> <Caption> WITH HEDGES WITHOUT HEDGES --------------------------- --------------------------- NINE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, 2002 2001 2002 2001 ------------ ------------ ------------ ------------ <S> <C> <C> <C> <C> Oil (per Bbl) $ 21.39 23.25 $ 22.08 24.04 Gas (per Mcf) 2.62 4.48 2.49 4.61 NGLs (per Bbl) 13.35 19.44 13.35 19.44 Oil, Gas and NGLs (per Boe) 16.75 25.37 16.38 26.10 </Table> OIL REVENUES. Oil revenues increased $27 million, or 14%, in the third quarter of 2002. Oil revenues increased $14 million due to a $1.36 per barrel increase in the average price of oil. An increase in 2002's production of 1 million barrels also caused oil revenues to increase. The October 2001 Anderson acquisition and the January 2002 Mitchell acquisition accounted for 3 million barrels of increased production, partially offset by production lost from divestitures of 2 million barrels. Oil revenues increased $97 million, or 16%, in the first nine months of 2002. An increase in production of 7 million barrels, or 28%, caused oil revenues to increase by $157 million. The Anderson and Mitchell acquisitions accounted for 8 million barrels of increased production, partially offset by production lost from divestitures of 2 million barrels. The effects of the production increase were partially offset by a $1.86 per barrel decrease in the average price of oil in 2002. GAS REVENUES. Gas revenues increased $177 million, or 58%, in the third quarter of 2002. An increase in production of 74 Bcf, or 66%, caused gas revenues to increase by $202 million. The Anderson and Mitchell acquisitions accounted for 94 Bcf of increased production, partially offset by production lost from divestitures of 10 Bcf, as well as natural declines in production. The effects of the production increase were partially offset by a $0.14 per Mcf decrease in the average gas price in the third quarter of 2002. 31
Gas revenues increased $43 million, or 3%, in the first nine months of 2002. An increase in production of 249 Bcf, or 76%, caused gas revenues to increase by $1.1 billion. The Anderson and Mitchell acquisitions accounted for 276 Bcf of increased production, partially offset by production lost from divestitures of 10 Bcf, as well as natural declines in production. The effects of the production increase were partially offset by a $1.86 per Mcf decrease in the average gas price in the first nine months of 2002. NGL REVENUES. NGL revenues increased $39 million in the third quarter of 2002. A 3 million barrel increase in 2002 production caused revenues to increase $47 million. The Anderson and Mitchell acquisitions accounted for 3 million barrels of increased production. The effects of the production increase were partially offset by a $1.65 per barrel decrease in the average NGL price in the third quarter of 2002. NGL revenues increased $102 million in the first nine months of 2002. A 10 million barrel increase in 2002 production caused revenues to increase $191 million. The Anderson and Mitchell acquisitions accounted for 10 million barrels of increased production. The effects of the production increase were partially offset by a $6.09 per barrel decrease in the average NGL price in the first nine months of 2002. MARKETING AND MIDSTREAM REVENUES. Marketing and midstream revenues increased $253 million and $645 million in the third quarter and first nine months of 2002, respectively. The Mitchell acquisition included significant marketing and midstream assets which accounted for the increase in revenues. PRODUCTION AND OPERATING EXPENSES. The components of production and operating expenses are set forth in the following tables. <Table> <Caption> TOTAL --------------------------------------------------------------------------- THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------------ ------------------------------------ 2002 2001 CHANGE 2002 2001 CHANGE ---------- ---------- ---------- ---------- ---------- ---------- ($'S IN MILLIONS) ABSOLUTE <S> <C> <C> <C> <C> <C> <C> Lease operating expenses $ 152 111 +37% 470 322 +46% Transportation costs 39 16 +144% 115 52 +121% Production taxes 25 21 +19% 80 94 -15% ---------- ---------- ---------- ---------- Total production and operating expenses $ 216 148 +46% 665 468 +42% ========== ========== ========== ========== PER BOE Lease operating expenses $ 3.39 3.83 -11% 3.29 3.78 -13% Transportation costs 0.88 0.56 +57% 0.80 0.61 +31% Production taxes 0.55 0.72 -24% 0.56 1.12 -50% ---------- ---------- ---------- ---------- Total production and operating expenses $ 4.82 5.11 -6% 4.65 5.51 -16% ========== ========== ========== ========== </Table> Lease operating expenses increased $41 million and $148 million in the third quarter and the first nine months of 2002, respectively. The Anderson and Mitchell acquisitions accounted for $66 million and $189 million of the increases, respectively. The historical Devon lease 32
operating expenses decreased $25 million and $41 million, respectively, due to divestitures, lower fuel and electricity costs as well as lower third-party field service costs. Transportation costs increased $23 million and $63 million in the third quarter and the first nine months of 2002, respectively, primarily due to an increase in gas production from the Anderson and Mitchell acquisitions. Production taxes increased $4 million in the third quarter of 2002 and decreased $14 million in the first nine months of 2002. 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 11% increase and 16% decrease in domestic oil, gas and NGL revenues in the third quarter and first nine months of 2002, respectively, were the primary causes of the production tax change. MARKETING AND MIDSTREAM COSTS AND EXPENSES. Marketing and midstream costs and expenses increased $209 million and $528 million in the third quarter and the first nine months of 2002, respectively. The Mitchell acquisition included significant marketing and midstream assets which accounted for the increase in costs and expenses. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES ("DD&A"). Oil and gas property related DD&A increased $70 million, or 38%, from $185 million in the third quarter of 2001 to $255 million in the third quarter of 2002. Oil and gas property related DD&A expense increased $102 million due to the 55% increase in combined oil, gas and NGLs production in 2002. The effects of the production increase were partially offset by a decrease in the combined U.S., Canadian and international DD&A rate from $6.41 per Boe in 2001 to $5.68 per Boe in 2002. The drop in the DD&A rate was primarily due to reductions of carrying value of oil and gas properties in the U.S. and Canada in the fourth quarter of 2001, and in Canada in the second quarter of 2002. Oil and gas property related DD&A increased $326 million, or 63%, from $515 million in the first nine months of 2001 to $841 million in the first nine months of 2002. Oil and gas property related DD&A expense increased $353 million due to the 68% increase in combined oil, gas and NGLs production in 2002. The effects of the production increase were partially offset by a decrease in the combined U.S., Canadian and international DD&A rate from $6.07 per Boe in 2001 to $5.88 per Boe in 2002. The rate decrease was primarily caused by the reductions to property previously discussed. Non-oil and gas property DD&A expense increased from $10 million in the third quarter of 2001 to $28 million in the third quarter of 2002. Non-oil and gas property DD&A expense increased from $29 million in the first nine months ended of 2001 to $77 million in the first nine months ended of 2002. Depreciation of the marketing and midstream assets acquired in the January 2002 Mitchell acquisition accounted for substantially all of 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 33
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 third quarter and first nine months of 2002 and 2001. <Table> <Caption> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> Gross G&A $ 92 60 281 172 Capitalized G&A (26) (18) (74) (56) Reimbursed G&A (19) (14) (56) (38) ------------ ------------ ------------ ------------ Net G&A $ 47 28 151 78 ============ ============ ============ ============ </Table> Net G&A increased $19 million and $73 million, or 68% and 94%, in the third quarter and first nine months of 2002, respectively, compared to the same periods of 2001. Gross G&A increased $32 million and $109 million, or 53% and 63%, in the third quarter and first nine months of 2002, respectively, compared to the same periods of 2001. The increase in gross expenses in both periods of 2002 was primarily related to the Anderson and Mitchell acquisitions. Capitalized G&A increased $8 million and $18 million in the third quarter and first nine months of 2002, respectively. Reimbursed G&A increased $5 million and $18 million in the third quarter and first nine months of 2002, respectively. Changes in both of the capitalized and reimbursed amounts were primarily related to the Anderson and Mitchell acquisitions. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES. Under the full cost method of accounting, the 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 cost of properties not subject to amortization. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely, and Devon does not include the effect of hedges in the calculation of the future net revenues. Therefore, the ceiling limitation is not necessarily indicative of the properties' fair value. 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, except as discussed in the following paragraph. If, subsequent to the end of the quarter but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the quarter. An expense recorded in one period may not be reversed in a subsequent period even 34
though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. Based on oil and natural gas cash market prices as of June 30, 2002, Devon's Canadian costs to be recovered exceeded the related ceiling value by $371 million. This after-tax amount resulted in a pre-tax reduction of the carrying value of Devon's Canadian oil and gas properties of $651 million in the second quarter of 2002. This reduction was the result of a sharp drop in Canadian gas prices during the last half of June 2002. The June 30 reference prices used in the Canadian ceiling calculation, expressed in Canadian dollars based on an exchange ratio of $0.6585, were a NYMEX price of C$40.79 per barrel of oil and an AECO price of C$2.17 per Mcf. The cash market prices of natural gas increased during the month of July 2002 prior to Devon's release of its second quarter results, but the increase was not sufficient to offset the entire reduction calculated as of June 30. Under the purchase method of accounting for business combinations, acquired oil and gas properties are recorded at fair value as of the date of purchase. Devon estimates such fair value using its estimates of future oil and gas prices. In contrast, the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely. Accordingly, the resulting value is not necessarily indicative of the fair value of the reserves. The oil and gas properties added from the Anderson acquisition in 2001 were recorded at fair values that were based on expected future oil and gas prices higher than the June 30, 2002, prices used to calculate the ceiling. During the third quarter of 2001, Devon elected to discontinue operations in Thailand. After meeting the drilling and capital commitments on this property, Devon determined that the property did not meet Devon's internal criteria to justify further investment. Accordingly, during the third quarter of 2001, Devon recorded a $10 million charge associated with the impairment of this property. The after-tax effect of this reduction was $7 million. During the first nine months of 2001, Devon elected to discontinue operations in Thailand, Malaysia, Qatar and on certain properties in Brazil. After meeting the drilling and capital commitments on these properties, Devon determined that these properties did not meet Devon's internal criteria to justify further investment. Accordingly, during the first nine months of 2001, Devon recorded an $87 million charge associated with the impairment of these properties. The after-tax effect of this reduction was $69 million. INTEREST EXPENSE. Interest expense increased $94 million and $297 million, or 261% and 283%, in the third quarter and first nine months of 2002, respectively, due to an increase in the average debt balance outstanding. The average debt balance increased from $2.0 billion in third quarter of 2001 to $7.9 billion in the 2002 quarter. The average debt balance increased from $1.9 billion in the first nine months of 2001 to $8.4 billion in the first nine months of 2002. The increase in the average debt balance in the 2002 periods caused interest expense to increase $92 million and $289 million in the third quarter and first nine months of 2002, respectively. This increase 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 6.5% in the 2001 quarter to 6.2% in the 2002 quarter and from 6.7% in the first nine 35
months of 2001 to 6.0% in the first nine months of 2002 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 periods. The overall rate decrease caused interest expense to decrease $1 million and $11 million in the third quarter and first nine months of 2002, respectively. Other items included in interest expense that are not related to the debt balance outstanding were $3 million and $19 million higher in the third quarter and first nine months of 2002, respectively. Of the $19 million increase in other items during the first nine months of 2002, $8 million related to the early extinguishment of the 8.75% senior notes. Items not related to the balance of debt outstanding include early retirement penalties, facility and agency fees, amortization of costs and other miscellaneous items. The following schedule includes the components of interest expense for the third quarter and first nine months of 2002 and 2001. <Table> <Caption> THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (IN MILLIONS) <S> <C> <C> <C> <C> Interest based on debt outstanding $ 124 33 376 98 Amortization of discounts 3 2 9 6 Facility and agency fees 1 -- 1 1 Amortization of capitalized loan costs 2 1 6 1 Capitalized interest (1) (1) (3) (2) Loss on early debt retirement -- -- 8 -- Other 1 1 5 1 ------------ ------------ ------------ ------------ Total interest expense $ 130 36 402 105 ============ ============ ============ ============ </Table> EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES. As a result of the Anderson acquisition, Devon's Canadian subsidiary has $400 million of 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 decrease in the Canadian-to-U.S. dollar exchange rate from $0.6585 at June 30, 2002 to $0.6306 at September 30, 2002 resulted in a $17 million loss in the third quarter of 2002. The September 30, 2002 exchange rate was substantially unchanged from the December 31, 2001 rate. Therefore, there was no gain or loss recorded for the nine months ended September 30, 2002. 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 (tax expense divided by pre-tax earnings) in the third quarter of 2002 was 25% compared to 39% in the third quarter of 2001. The estimated effective tax rate was a benefit of 83% in the first nine months of 2002 compared to an expense of 40% in the first nine months of 2001. Excluding the effect of the reduction of carrying value of Canadian oil and gas properties, the effective tax rate was 24% in the first nine months of 2002. 36
The 2002 rates, excluding the Canadian writedown, were lower than the statutory federal tax rate primarily due to the tax benefits of certain foreign deductions. The 2001 rates were 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 September 30, 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. CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE. On January 1, 2001, Devon adopted 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 $3.0 billion was spent in the first nine months of 2002 for capital expenditures. This total includes $1.7 billion related to the January 2002 Mitchell acquisition; $1.2 billion for other acquisitions and the drilling or development of oil and gas properties; and $0.1 billion related to marketing and midstream assets. These amounts compare to capital expenditures of $1.3 billion (substantially all of which was related to the acquisition, drilling or development of oil and gas properties) in the first nine months of 2001. 37
OTHER CASH USES. Devon's common stock dividends were $23 million and $20 million in the first nine months of 2002 and 2001, respectively. Devon also paid $7 million of preferred stock dividends in each of the first nine months 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 has been sales of oil and gas properties. Net cash provided by operating activities ("operating cash flow") continued to be a primary source of capital and liquidity in the first nine months of 2002. Operating cash flow in the first nine months of 2002 was $1.2 billion, compared to $1.5 billion in the first nine months of 2001. The decrease in operating cash flow in the first nine months of 2002 was primarily caused by the decline in commodity prices 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 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 September 30, 2002. <Table> <Caption> Fixed-Price Physical Price Swap Price Delivery Contracts Contracts Collars Total -------------------- ---------- ------- ----- <S> <C> <C> <C> Oil production (MMBbls) 2002 2 10 7 19 2003 -- -- 17 17 Natural gas production (Bcf) 2002 73 106 174 353 2003 16 34 195 245 2004 16 -- 18 34 </Table> For the years 2005 through 2011, Devon has fixed-price physical delivery contracts covering Canadian natural gas production ranging from 8 Bcf to 14 Bcf per year. Thereafter, 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. 38
Other sources of liquidity are Devon's revolving lines of credit. On June 7, 2002, Devon renewed the $800 million, 364-day portion of its unsecured long-term credit facilities (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $1.4 million that is payable quarterly. The $725 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $525 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until June 5, 2003 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. On June 6, 2003, at the end of the Tranche B Revolving Period, Devon may convert the then outstanding balance under the Tranche B facility to a two-year term loan by paying the Agent a fee of 12.5 basis points. The applicable borrowing rate would be at LIBOR plus 125 basis points. On September 30, 2002, there were no borrowings outstanding under the $725 million U.S. Facility. The available capacity under the U.S. Facility as of September 30, 2002, net of commercial paper borrowings and outstanding letters of credit, was $623 million. Devon may borrow funds under the $275 million Canadian Facility until June 5, 2003 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semiannual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. On September 30, 2002, there were no borrowings under the $275 million Canadian facility. Under the terms of the Credit Facilities, Devon has the right to reallocate up to $100 million of the unused Tranche B facility maximum credit amount to the Canadian Facility. Conversely, Devon also has the right to reallocate up to $100 million of unused Canadian Facility maximum credit amount to the Tranche B Facility. On July 25, 2002, Devon renewed and increased its letter of credit and revolving bank facility ("LOC Facility") for its Canadian operations. This C$150 million LOC Facility will be used primarily by Devon's wholly-owned subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to issue letters of credit. As of September 30, 2002, C$105 million ($ 66 million converted to U.S. dollars using the September 30, 2002 exchange rate) of letters of credit were issued under the LOC Facility primarily for Canadian drilling commitments. 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 39
it can have a maturity of up to 365 days. Devon had $78 million of commercial paper debt outstanding at September 30, 2002, at an average interest rate of 2.3%. 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 September 30, 2002, $1.9 billion of the balance outstanding was retired. The primary sources of the repayments were the issuance of $1 billion of debt securities, of which $0.8 billion was used to pay down debt, and $1.1 billion from the sale of certain oil and gas properties. The remaining balance outstanding as of September 30, 2002 will mature as follows: <Table> <Caption> (In Millions) ------------- <S> <C> April 15, 2006 $ 335 October 15, 2006 800 -------- $ 1,135 ======== </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 was fixed at 100 basis points. Thereafter, the margin is based on Devon's debt rating. Based on Devon's current debt rating, the margin after June 17, 2002, is 100 basis points. As of September 30, 2002, the average interest rate on this facility was 2.8%. 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 65%. 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 September 30, 2002, Devon's ratio of total funded debt to total capitalization, as defined in its credit agreements, was 55.8%. On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15, 2032. The net proceeds received, after discounts and issuance costs, were $986 million. The debt securities are unsecured and unsubordinated obligations of Devon. The net proceeds were partially used to pay down $820 million on Devon's $3 billion term loan credit facility. The remaining $166 million of net proceeds was used in June 2002 to partially fund the early extinguishment of $175 million of 8.75% senior notes due June 15, 2007. The notes were redeemed 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 $1.4 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. 40
As of October 31, 2002, Devon has closed sales of Disposition Properties totaling $1.4 billion in proceeds. In addition, Devon has identified approximately $100 million of Disposition Properties that could be sold in the fourth quarter of 2002. A summary of Devon's contractual obligations as of September 30, 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 $ -- -- 414 350 1,265 5,722 7,751 Operating leases 32 30 22 15 11 14 124 Drilling obligations 173 125 43 45 1 -- 387 Firm transportation agreements 96 93 78 59 52 245 623 ---------- ---------- ---------- ---------- ---------- ---------- ---------- Total $ 301 248 557 469 1,329 5,981 8,885 ========== ========== ========== ========== ========== ========== ========== </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. The above table does not include $90 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 $7.8 billion of long-term debt shown in the table excludes $105 million of discounts included in the September 30, 2002, book balance of the debt. PROPERTY DIVESTITURES During 2002, Devon estimates that it will sell certain oil and gas properties (the "Disposition Properties") for between $1.4 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 October 31, 2002, Devon has closed sales of Disposition Properties totaling $1.4 billion in proceeds. The Disposition Properties' actual contribution to Devon's 2002 operating results depends upon when the transactions to sell the Disposition Properties closed. The following table presents the Disposition Properties' quarterly operating results. No information is included in the following table for fourth quarter 2002 due to the immaterial effect that any fourth quarter sales are expected to have on Devon's results. The following table includes production and expenses from International Disposition Properties in Indonesia and Argentina. However, this is different from the actual financial presentation that results from the divestiture of these properties. Pursuant to Statement of 41
Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the International assets sold constitute a "component of an entity." As such, in the period in which such International properties are sold, the related operating results are reported as discontinued operations. The prior periods' operating results related to such assets are also 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 have been netted and reported as discontinued operations in the accompanying consolidated financial statements. The results of the domestic and Canadian Disposition Properties are not presented as discontinued operations due to significant continuing operations in the United States and Canada. <Table> <Caption> ACTUAL RESULTS ------------------------------------------ 1ST 2ND 3RD QUARTER QUARTER QUARTER 2002 2002 2002 ------------ ------------ ------------ <S> <C> <C> <C> OIL (MMBBLS) United States 1.3 1.5 0.3 Canada 1.2 0.6 0.1 International 1.7 0.8 0.7 ------------ ------------ ------------ Total 4.2 2.9 1.1 ============ ============ ============ GAS (Bcf) United States 12 11 2 Canada 4 3 1 International 2 2 1 ------------ ------------ ------------ Total 18 16 4 ============ ============ ============ NGLS (MMBBLS) United States 0.3 0.3 0.1 Canada 0.1 0.1 -- International 0.1 -- -- ------------ ------------ ------------ Total 0.5 0.4 0.1 ============ ============ ============ LEASE OPERATING EXPENSES (IN MILLIONS) United States $ 22 16 4 Canada 10 6 2 International 15 7 4 ------------ ------------ ------------ Total 47 29 10 ============ ============ ============ TRANSPORTATION COSTS (IN MILLIONS) United States $ 1 1 -- Canada 1 1 1 International -- -- -- ------------ ------------ ------------ Total 2 2 1 ============ ============ ============ DD&A (IN MILLIONS) United States $ 23 22 4 Canada 12 7 1 International 8 6 4 ------------ ------------ ------------ Total 43 35 9 ============ ============ ============ </Table> 42
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 present value of expected cash outflows 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 includes estimated costs of dismantlement, removal, site reclamation, and other similar activities in the total costs that are subject to depreciation, depletion, and amortization. Devon does not record a separate asset or 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. 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. SFAS No. 145 will be effective for fiscal years beginning after May 15, 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses From Extinguishment of Debt, and requires that all gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. Devon will adopt the provisions related to the rescission of SFAS No. 4 as of January 1, 2003. In 1999, Devon recorded a $4 million extraordinary loss related to the early extinguishment of long-term debt. Upon adopting SFAS No. 145 in 2003, this extraordinary loss will be reclassified as interest expense in any presentation of Devon's results that includes the year 1999. The FASB issued Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities, in June 2002. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs incurred in a Restructuring). SFAS No. 146 43
applies to costs incurred in an "exit activity", which includes, but is not limited to, a restructuring, or a "disposal activity" covered by SFAS No. 144. SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Previously, under Issue 94-3, a liability for an exit cost was recognized at the date of an entity's commitment to an exit plan. Statement No. 146 also establishes that fair value is the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. Devon currently has no such exit or disposal activities planned. 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, and the update of such information included in Item 3 of Devon's Quarterly Report on Form 10-Q for the period ended June 30, 2002, 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 September 30, 2002, there have been no material changes in Devon's market risk exposure from that disclosed in the June 30, 2002 Form 10-Q. ITEM 4. CONTROLS AND PROCEDURES We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Our principal executive and financial officers have evaluated our disclosure controls and procedures within 90 days prior to the filing of this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective. Subsequent to their evaluation, there were no significant changes in internal controls or other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses. 44
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 None ITEM 5. OTHER INFORMATION None 45
ITEM 6.EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits required by Item 601 of Regulation S-K are as follows: Exhibit No. 4.1 Second Supplemental Indenture, dated as of October 31, 2002, by and between Devon Energy Production Company, L.P., as Successor to the Issuer, and The Bank of New York, as Trustee supplementing the Indenture dated as of June 1, 1999, as supplemented by the First Supplemental Indenture, dated as of June 14, 1999, by and between Devon SFS Operating, Inc. and the Trustee 99.1 Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.2 Certification of William T. Vaughn, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (b) Reports on Form 8-K. A Report on Form 8-K was filed August 14, 2002 to announce that Devon's Chief Executive Officer and Chief Financial Officer, each filed with the Securities and Exchange Commission a statement under oath regarding facts and circumstances relating to the accuracy of Devon's financial statements and each of their consultations with Devon's Audit Committee, as required by the Securities and Exchange Commission's "Order Requiring the Filing of Sworn Statements Pursuant to Section 21(a)(1) of the Securities Exchange Act of 1934" (File No. 4-460, June 27, 2002). A Report on Form 8-K was filed October 3, 2002 to reclassify Devon's Indonesian activities as discontinued operations following the sale of those operations to PetroChina Company Limited. 46
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: November 13, 2002 /s/ Danny J. Heatly -------------------------------- Danny J. Heatly Vice President - Accounting 47
CERTIFICATION I, J. Larry Nichols, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Devon Energy Corp.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 13, 2002 /s/ J. Larry Nichols ---------------------------------- J. Larry Nichols Chief Executive Officer 48
CERTIFICATION I, William T. Vaughn, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Devon Energy Corp.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 13, 2002 /s/ William T. Vaughn ------------------------------- William T. Vaughn Chief Financial Officer 49
INDEX TO EXHIBITS <Table> <Caption> EXHIBIT NUMBER DESCRIPTION ------ ----------- <S> <C> 4.1 Second Supplemental Indenture, dated as of October 31, 2002, by and between Devon Energy Production Company, L.P., as Successor to the Issuer, and The Bank of New York, as Trustee, supplementing the Indenture dated as of June 1, 1999, as supplemented by the First Supplemental Indenture, dated as of June 14, 1999, by and between Devon SFS Operating, Inc. and the Trustee. 99.1 Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.2 Certification of William T. Vaughn, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 </Table>