1 ================================================================================ ` 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 June 30, 2001 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) <Table> <S> <C> DELAWARE 73-1567067 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification Number) 20 NORTH BROADWAY, SUITE 1500 OKLAHOMA CITY, OKLAHOMA 73102-8260 (Address of Principal Executive Offices) (Zip Code) </Table> 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 July 31, 2001, was 125,984,000. 1 of 67 total pages (Exhibit Index is found at page 35)
2 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, June 30, 2001 (Unaudited) 4 and December 31, 2000 Consolidated Statements of Operations (Unaudited) 5 for the Three Months and Six Months Ended June 30, 2001 and 2000 Consolidated Statements of Comprehensive Operations 6 (Unaudited) for the Three Months and Six Months Ended June 30, 2001 and 2000 Consolidated Statements of Cash Flows (Unaudited) 7 for the Six Months Ended June 30, 2001 and 2000 Notes to Consolidated Financial Statements 8 Item 2. Management's Discussion and Analysis of Financial 20 Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk 31 Part II. Other Information Item 4. Submission of Matters to a Vote of Security Holders 32 Item 6. Exhibits and Reports on Form 8-K 33 </Table> DEFINITIONS As used in this document: "Mcf" means thousand cubic feet "MMcf" means million cubic feet "Bcf" means billion cubic feet "Bbl" means barrel "MBbls" means thousand barrels "MMBbls" means million barrels "Boe" means equivalent barrels of oil "Mboe" means thousand equivalent barrels of oil "Oil" includes crude oil and condensate "NGL" means natural gas liquids 2
3 DEVON ENERGY CORPORATION PART I. FINANCIAL INFORMATION ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 2001 AND 2000 (FORMING A PART OF FORM 10-Q QUARTERLY REPORT TO THE SECURITIES AND EXCHANGE COMMISSION) 3
4 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA) <Table> <Caption> JUNE 30, DECEMBER 31, 2001 2000 ------------ ------------ (UNAUDITED) <S> <C> <C> ASSETS Current assets: Cash and cash equivalents $ 477,822 228,050 Accounts receivable 550,661 615,463 Inventories 40,193 47,272 Deferred income taxes 8,979 8,979 Investments and other current assets 33,858 34,373 ------------ ------------ Total current assets 1,111,513 934,137 ------------ ------------ Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties 10,865,921 9,709,352 Less accumulated depreciation, depletion and amortization 5,225,784 4,799,816 ------------ ------------ 5,640,137 4,909,536 Investment in Chevron Corporation common stock, at fair value 641,865 598,867 Goodwill, net of amortization 277,767 289,489 Other assets 132,756 128,449 ------------ ------------ Total assets $ 7,804,038 6,860,478 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade 296,516 305,210 Revenues and royalties due to others 125,012 151,951 Income taxes payable 48,649 65,674 Accrued interest payable 23,488 23,191 Merger related expenses payable 19,013 36,981 Accrued expenses and other current liabilities 75,159 45,980 ------------ ------------ Total current liabilities 587,837 628,987 ------------ ------------ Other liabilities 167,977 164,469 Debentures exchangeable into shares of Chevron Corporation common stock 642,329 760,313 Other long-term debt 1,438,819 1,288,523 Deferred revenue 81,472 113,756 Fair value of derivative instruments 17,979 -- Deferred income taxes 1,010,384 626,826 Stockholders' equity: Preferred stock of $1.00 par value ($100 liquidation value) Authorized 4,500,000 shares; issued 1,500,000 in 2001 and 2000 1,500 1,500 Common stock of $.10 par value Authorized 400,000,000 shares; issued 129,628,000 in 2001 and 128,638,000 in 2000 12,963 12,864 Additional paid-in capital 3,590,233 3,563,994 Retained earnings (accumulated deficit) 304,130 (214,708) Accumulated other comprehensive loss (43,313) (85,397) Unamortized restricted stock awards (487) (649) Treasury stock, at cost; 153,000 shares in 2001 (7,785) -- ------------ ------------ Total stockholders' equity 3,857,241 3,277,604 ------------ ------------ Total liabilities and stockholders' equity $ 7,804,038 6,860,478 ============ ============ </Table> See accompanying notes to consolidated financial statements. 4
5 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <Table> <Caption> THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------- ------------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- (UNAUDITED) <S> <C> <C> <C> <C> REVENUES Oil sales $ 234,574 274,778 488,556 544,935 Gas sales 443,014 327,460 1,168,178 568,277 Natural gas liquids sales 31,964 33,539 64,301 70,916 Other 15,610 12,707 27,714 24,772 ---------- ---------- ---------- ---------- Total revenues 725,162 648,484 1,748,749 1,208,900 ---------- ---------- ---------- ---------- COSTS AND EXPENSES Lease operating expenses 115,455 111,100 238,103 217,807 Transportation costs 18,419 12,932 35,823 24,745 Production taxes 29,549 22,473 74,058 41,871 Depreciation, depletion and amortization of property and equipment 184,702 172,251 367,594 337,503 Amortization of goodwill 8,461 10,361 16,923 20,693 General and administrative expenses 24,628 24,023 46,890 48,873 Interest expense 34,402 40,875 68,940 80,951 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- -- -- 2,408 Reduction of carrying value of oil and gas properties 76,942 -- 76,942 -- ---------- ---------- ---------- ---------- Total costs and expenses 492,558 394,015 925,273 774,851 ---------- ---------- ---------- ---------- Earnings before change in fair value of derivative instruments, income tax expense, and cumulative effect of change in accounting principle 232,604 254,469 823,476 434,049 Change in fair value of derivative instruments 7,460 -- (6,582) -- ---------- ---------- ---------- ---------- Earnings before income tax expense and cumulative effect of change in accounting principle 240,064 254,469 816,894 434,049 INCOME TAX EXPENSE (BENEFIT) Current (1,204) 36,358 142,892 72,505 Deferred 104,878 64,777 186,797 ---------- ---------- ---------- ---------- 103,023 Total income tax expense 103,674 101,135 329,689 175,528 ---------- ---------- ---------- ---------- Earnings before cumulative effect of change in accounting principle 136,390 153,334 487,205 258,521 Cumulative effect of change in accounting principle, net of income tax expense of $31,617 -- -- 49,452 -- ---------- ---------- ---------- ---------- Net earnings 136,390 153,334 536,657 258,521 Preferred stock dividends 2,434 2,434 4,868 4,868 ---------- ---------- ---------- Net earnings applicable to common shareholders $ 133,956 150,900 531,789 253,653 ========== ========== ========== ========== Net earnings before cumulative effect of change in accounting principle per average common share outstanding: Basic $ 1.03 1.19 3.73 2.00 ========== ========== ========== ========== Diluted $ 1.01 1.17 3.59 1.97 ========== ========== ========== ========== Net earnings per average common share outstanding: Basic $ 1.03 1.19 4.11 2.00 ========== ========== ========== ========== Diluted $ 1.01 1.17 3.96 1.97 ========== ========== ========== ========== Weighted average common shares outstanding-basic 129,488 126,994 129,260 126,675 ========== ========== ========== ========== Weighted average common shares outstanding-diluted 135,403 129,455 135,402 128,681 ========== ========== ========== ========== </Table> See accompanying notes to consolidated financial statements. 5
6 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS (IN THOUSANDS) <Table> <Caption> THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------- --------------------- 2001 2000 2001 2000 -------- -------- -------- -------- (UNAUDITED) <S> <C> <C> <C> <C> Net earnings $136,360 153,334 536,657 258,521 Other comprehensive earnings (loss), net of tax: Foreign currency translation adjustments 15,882 (5,420) (3,752) (5,775) Cumulative effect of change in accounting principle -- -- (36,579) -- Reclassification adjustment for derivative losses reclassified into oil and gas sales 10,320 -- 14,963 -- Change in fair value of outstanding hedging positions 27,766 -- 41,225 -- Unrealized gains (losses) on marketable securities 11,682 (31,489) 26,229 (6,042) -------- -------- -------- -------- Comprehensive earnings $202,010 116,425 578,743 246,704 ======== ======== ======== ======== </Table> See accompanying notes to consolidated financial statements. 6
7 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) <Table> <Caption> SIX MONTHS ENDED JUNE 30, -------------------------- 2001 2000 ----------- ----------- (UNAUDITED) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Net earnings $ 536,657 258,521 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation, depletion and amortization of property and equipment 367,594 337,503 Amortization of goodwill 16,923 20,693 Reduction of carrying value of oil and gas properties 76,942 -- Accretion of interest on zero coupon convertible senior debentures 7,007 114 Amortization of discounts (premiums) on other long-term debt 4,027 (1,946) Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- 2,408 Gain on sale of assets 327 44 Change in fair value of derivative instruments 6,582 -- Cumulative effect of change in accounting principle (49,452) -- Deferred income taxes 186,797 103,023 Other 1,042 2,174 Changes in assets and liabilities: Decrease (increase) in: Accounts receivable 54,393 (130,584) Inventories 8,088 (4,808) Prepaid expenses 17,755 (14,164) Other assets (15,806) (9,027) (Decrease) increase in: Accounts payable (12,423) 46,484 Income taxes payable (17,007) 47,270 Accrued expenses and other current liabilities (10,779) (15,813) Deferred revenue (32,269) 45,500 Long-term other liabilities (19,680) (21,176) ----------- ----------- Net cash provided by operating activities 1,126,718 666,442 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of property and equipment 25,940 43,064 Capital expenditures (1,018,759) (719,027) Decrease in other assets -- 186 ----------- ----------- Net cash used in investing activities (992,819) (675,777) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings of long-term debt, net of issuance costs 365,668 1,126,321 Principal payments on long-term debt (257,667) (984,412) Issuance of common stock, net of issuance costs 39,674 27,426 Repurchase of common stock (13,337) (10,600) Issuance of treasury stock -- 11,600 Dividends paid on common stock (12,951) (8,663) Dividends paid on preferred stock (4,868) (4,868) Decrease in long-term other liabilities (60) (6,601) ----------- ----------- Net cash provided by financing activities 116,459 150,203 ----------- ----------- Effect of exchange rate changes on cash (587) (764) ----------- ----------- Net increase in cash and cash equivalents 249,771 140,104 Cash and cash equivalents at beginning of period 228,050 173,167 ----------- ----------- Cash and cash equivalents at end of period $ 477,822 313,271 =========== =========== </Table> See accompanying notes to consolidated financial statements. 7
8 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES On August 29, 2000, Devon Energy Corporation ("Devon") and Santa Fe Snyder Corporation ("Santa Fe Snyder") completed a merger of the two companies (the "Santa Fe Snyder merger"). At that date, Santa Fe Snyder became a wholly-owned subsidiary of Devon. The Santa Fe Snyder merger was accounted for under the pooling-of-interests method of accounting for business combinations. All operational and financial information contained herein includes the combined amounts of Devon and Santa Fe Snyder for all periods presented. The accompanying consolidated financial statements and notes thereto have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in Devon's 2000 Annual Report on Form 10-K. In the opinion of Devon's management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of June 30, 2001, and the results of their operations and their cash flows for the three-month and six-month periods ended June 30, 2001 and 2000. Certain of the 2000 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2001 presentation. 2. PENDING ACQUISITION On August 14, 2001, Devon and Mitchell Energy & Development Corporation ("Mitchell Energy") announced that Devon will acquire Mitchell Energy for cash and stock. In the transaction, Mitchell Energy stockholders would receive, for each Mitchell common share, $31 cash and 0.585 of a share of Devon common stock. The transaction is subject to approval by the stockholders of both companies, as well as certain regulatory approvals. If approved, the transaction is expected to be consummated shortly after the stockholder meetings. Mitchell Energy's estimated June 30, 2001 proved oil and gas reserves totaled 2.5 trillion cubic feet of gas equivalent located in the United States. In the transaction, Devon would also acquire Mitchell Energy's natural gas processing plants, pipelines and other midstream assets valued between $800 million and $1 billion. 3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES As of January 1, 2001, Devon adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Certain Hedging Activities" and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment of SFAS No. 133." SFAS No. 133 and SFAS No. 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values. In accordance with the transition provisions of SFAS No. 133, Devon recorded a net-of-tax cumulative-effect-type adjustment of a $36.6 million loss in accumulated other comprehensive loss to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. Additionally, Devon recorded a net-of-tax cumulative-effect-type adjustment to net earnings for a $49.5 million gain ($0.38 per basic share and $0.37 per diluted share) related to the fair value of derivative instruments that do not qualify as hedges. This gain related principally to the option embedded in Devon's debentures that are exchangeable into shares of Chevron Corporation common stock. All derivatives are recognized on the balance sheet at their fair value. All of Devon's derivatives that qualify for hedge accounting treatment are either "cash flow" hedges or "foreign currency cash flow" hedges (collectively, "cash flow hedges"). Devon designates its cash flow hedge derivatives as such on the date the derivative contract is entered into. Devon formally 8
9 documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. Devon also assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. During the first half of 2001, there were no gains or losses reclassified into earnings as a result of the discontinuance of hedge accounting treatment for any of Devon's derivatives. By using derivative instruments to hedge exposures to changes in commodity prices and exchange rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are usually placed with counterparties that Devon believes are minimal credit risks. Market risk is the adverse effect on the value of a derivative instrument that results from a change in interest rates, commodity prices, or currency exchange rates. The market risk associated with commodity price and foreign exchange contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. Devon periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through various financial transactions to manage its exposure to oil and gas price volatility. These transactions include financial price swaps whereby Devon will receive a fixed price for its production and pay a variable market price to the contract counterparty. These transactions also include costless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage Devon's exposure to oil and gas price fluctuations. The oil and gas reference prices upon which these price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon. Devon also periodically enters into foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are predominantly based on U.S. dollar prices. Devon does not hold or issue derivative instruments for trading purposes. All of Devon's commodity price swaps and costless price collars and foreign exchange rate swaps in place at January 1, 2001 and June 30, 2001 have been designated as cash flow hedges. Changes in the fair value of these derivatives are reported on the balance sheet in "Accumulated other comprehensive loss" ("AOCL"). These amounts are reclassified to oil and gas sales when the forecasted transaction takes place. Devon assesses the effectiveness of its hedges based on changes in the derivative's intrinsic value. The change in the time value of the derivative is excluded from the assessment of hedge effectiveness and, along with any ineffectiveness, is recorded on the statement of 9
10 operations in "Change in fair value of derivative instruments." For the three- and six-month periods ended June 30, 2001, Devon recorded a net charge of less than $0.1 million which represented the ineffectiveness of the various cash flow hedges. As of June 30, 2001, $14.2 million of net deferred gains on derivative instruments accumulated in AOCL are expected to be reclassified to earnings 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 are the production and sale of oil and gas which includes the production hedged under the various derivative instruments. The maximum term over which Devon is hedging exposures to the variability of cash flows for commodity price risk is 18 months. Devon recorded a gain of $7.5 million and an expense of $6.6 million in the three-month and six-month periods ended June 30, 2001, respectively, for the change in fair value of derivative instruments. Substantially all of this expense related to the fair value change in the option that is embedded in Devon's debentures which are exchangeable into shares of Chevron Corporation common stock. 4. EARNINGS PER SHARE The following tables reconcile the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month and six-month periods ended June 30, 2001 and 2000. <Table> <Caption> NET EARNINGS NET APPLICABLE COMMON EARNINGS TO COMMON SHARES PER STOCKHOLDERS OUTSTANDING SHARE ------------ ----------- --------- (IN THOUSANDS) <S> <C> <C> <C> THREE MONTHS ENDED JUNE 30, 2001: Basic earnings per share $133,956 129,488 $ 1.03 ======== 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 $1,382) 2,161 4,377 Potential common shares issuable upon the exercise of outstanding stock options -- 1,538 -------- -------- Diluted earnings per share $136,117 135,403 $ 1.01 ======== ======== ======== </Table> 10
11 4. EARNINGS PER SHARE (CONTINUED) <Table> <S> <C> <C> <C> THREE MONTHS ENDED JUNE 30, 2000: Basic earnings per share $150,900 126,994 $ 1.19 ======== 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 $46) 71 192 Potential common shares issuable upon the exercise of outstanding stock options -- 2,269 -------- ------- Diluted earnings per share $150,971 129,455 $ 1.17 ======== ======== ======== SIX MONTHS ENDED JUNE 30, 2001: Basic earnings per share $531,789 129,260 $ 4.11 ======== 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 $2,762) 4,321 4,377 Potential common shares issuable upon the exercise of outstanding stock options -- 1,765 -------- ------- Diluted earnings per share $536,110 135,402 $ 3.96 ======== ======== ======== SIX MONTHS ENDED JUNE 30, 2000: Basic earnings per share $253,653 126,675 $ 2.00 ======== 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 $46) 71 96 Potential common shares issuable upon the exercise of outstanding stock options -- 1,910 -------- ------- Diluted earnings per share $253,724 128,681 $ 1.97 ======== ======== ======== </Table> 11
12 4. EARNINGS PER SHARE (CONTINUED) Options to purchase approximately 1.0 million shares of Devon's common stock with exercise prices ranging from $56.76 per share to $89.66 per share (with a weighted average price of $65.31 per share) were outstanding at June 30, 2001, but were not included in the computation of diluted earnings per share for the second quarter of 2001 because the options' exercise price exceeded the average market price of Devon's common stock during the second quarter. Similarly, options to purchase approximately 1.4 million shares of Devon's common stock with exercise prices ranging from $55.53 per share to $92.78 per share (with a weighted average price of $65.97 per share) were excluded from the diluted earnings per share calculation for the second quarter of 2000. Options to purchase approximately 1.0 million shares of Devon's common stock, with exercise prices from $57.72 to $89.66 per share (with a weighted average price of $65.34 per share), were excluded from the diluted earnings per share calculation for first six months of 2001. Similarly, options to purchase approximately 1.8 million shares of Devon's common stock with exercise prices ranging from $49.94 per share to $92.78 per share (with a weighted average price of $62.08 per share) were excluded from the diluted earnings per share calculation for the first six months of 2000. The excluded options for each of the 2001 periods expire between September 13, 2001 and May 17, 2011. 5. STOCK BUYBACK Effective June 27, 2001, the board of directors authorized the repurchase of up to $1 billion of Devon's common stock. The repurchase program also applies to securities that are convertible into, or otherwise equity-linked to, Devon's common stock. Under the repurchase program, share purchases may be made from time to time depending upon market conditions and may be made in the open market and in privately negotiated transactions. The repurchase program may be discontinued at any time. During the second quarter of 2001, Devon repurchased 153,000 shares of common stock at an aggregate cost of $7.8 million or $51.05 per share. As of July 31, 2001, Devon had repurchased 3,754,000 shares of common stock at an aggregate cost of $190.4 million or $50.71 per share. In addition to the aforementioned share repurchase program begun in the second quarter of 2001, Devon also repurchased shares of its common stock in the first quarter of 2001 under an odd-lot repurchase program. Pursuant to this program, Devon purchased and retired 232,000 shares of its common stock for a total cost of $13.3 million, or $57.40 per share. 6. LONG-TERM DEBT As of June 30, 2001, Devon had borrowings outstanding under its unsecured long-term credit facilities (the "Credit Facilities") of $92.2 million at an average rate of 4.8%. Also, as of June 30, 2001, Devon had $199.8 million of borrowings under its commercial paper program at an average rate of 4.2%. Because Devon had the intent and ability to refinance the balance due with borrowings under its Credit Facilities, the $199.8 million outstanding under the commercial paper program was classified as long-term debt on the June 30, 2001 consolidated balance sheet. 12
13 7. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES During the second quarter of 2001, Devon elected to discontinue operations in Malaysia, Qatar and on certain properties in Brazil. Accordingly, during the second quarter of 2001, Devon recorded a $76.9 million charge associated with the impairment of these properties. The after-tax effect of this reduction was $62.1 million. 8. 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 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 THOUSANDS) <S> <C> <C> <C> <C> AS OF JUNE 30, 2001: Current assets $ 755,110 68,761 287,642 1,111,513 Property and equipment, net of accumulated depreciation, depletion and amortization 4,280,010 650,731 709,396 5,640,137 Investment in Chevron Corporation common stock 641,865 -- -- 641,865 Goodwill, net of amortization 230,431 -- 47,336 277,767 Other assets 119,123 82 13,551 132,756 ---------- ---------- ---------- ---------- Total assets $6,026,539 719,574 1,057,925 7,804,038 ========== ========== ========== ========== Current liabilities 366,257 73,644 147,936 587,837 Other liabilities 132,246 888 34,843 167,977 Debentures exchangeable into shares of Chevron Corporation common stock 642,329 -- -- 642,329 Other long-term debt 1,346,573 92,246 -- 1,438,819 Deferred revenue 80,444 537 491 81,472 Fair value of derivative instruments 12,110 5,869 -- 17,979 Deferred income taxes 874,839 113,475 22,070 1,010,384 Stockholders' equity 2,571,741 432,915 852,585 3,857,241 ---------- ---------- ---------- ---------- Total liabilities and stockholders' equity $6,026,539 719,574 1,057,925 7,804,038 ========== ========== ========== ========== </Table> 13
14 8. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL --------- --------- --------- --------- (IN THOUSANDS) <S> <C> <C> <C> <C> THREE MONTHS ENDED JUNE 30, 2001: REVENUES Oil sales $ 144,352 28,977 61,245 234,574 Gas sales 387,627 52,104 3,283 443,014 Natural gas liquids sales 27,472 4,197 295 31,964 Other 10,362 637 4,611 15,610 --------- --------- --------- --------- Total revenues 569,813 85,915 69,434 725,162 --------- --------- --------- --------- COSTS AND EXPENSES Lease operating expenses 79,343 16,782 19,330 115,455 Transportation costs 15,414 3,005 -- 18,419 Production taxes 28,910 475 164 29,549 Depreciation, depletion and amortization of property and equipment 147,444 20,000 17,258 184,702 Amortization of goodwill 8,450 -- 11 8,461 General and administrative expenses 25,266 1,914 (2,552) 24,628 Interest expense 32,750 1,397 255 34,402 Reduction of carrying value of oil and gas properties -- -- 76,942 76,942 --------- --------- --------- --------- Total costs and expenses 337,577 43,573 111,408 492,558 --------- --------- --------- --------- Earnings (loss) before change in fair value of derivative instruments and income tax expense 232,236 42,342 (41,974) 232,604 Change in fair value of derivative instruments 7,460 -- -- 7,460 --------- --------- --------- --------- Earnings (loss) before income tax expense 239,696 42,342 (41,974) 240,064 INCOME TAX EXPENSE (BENEFIT) Current (8,790) 974 6,612 (1,204) Deferred 97,114 14,892 (7,128) 104,878 --------- --------- --------- --------- Total income tax expense (benefit) 88,324 15,866 (516) 103,674 --------- --------- --------- --------- Net earnings (loss) 151,372 26,476 (41,458) 136,390 Preferred stock dividends 2,434 -- -- 2,434 --------- --------- --------- --------- Net earnings (loss) applicable to common shareholders $ 148,938 26,476 (41,458) 133,956 ========= ========= ========= ========= Capital expenditures $ 565,937 48,477 58,419 672,833 ========= ========= ========= ========= </Table> 14
15 8. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL -------- -------- -------- -------- (IN THOUSANDS) <S> <C> <C> <C> <C> THREE MONTHS ENDED JUNE 30, 2000: REVENUES Oil sales $187,842 27,695 59,241 274,778 Gas sales 287,964 36,496 3,000 327,460 Natural gas liquids sales 29,270 4,169 100 33,539 Other 10,466 1,231 1,010 12,707 -------- -------- -------- -------- Total revenues 515,542 69,591 63,351 648,484 -------- -------- -------- -------- COSTS AND EXPENSES Lease operating expenses 79,802 12,921 18,377 111,100 Transportation costs 9,992 2,940 -- 12,932 Production taxes 22,076 297 100 22,473 Depreciation, depletion and amortization of property and equipment 144,836 16,359 11,056 172,251 Amortization of goodwill 10,355 -- 6 10,361 General and administrative expenses 20,725 2,541 757 24,023 Interest expense 38,007 2,568 300 40,875 -------- -------- -------- -------- Total costs and expenses 325,793 37,626 30,596 394,015 -------- -------- -------- -------- Earnings before income tax expense 189,749 31,965 32,755 254,469 INCOME TAX EXPENSE Current 32,379 279 3,700 36,358 Deferred 39,751 14,353 10,673 64,777 -------- -------- -------- -------- Total income tax expense 72,130 14,632 14,373 101,135 -------- -------- -------- -------- Net earnings 117,619 17,333 18,382 153,334 Preferred stock dividends 2,434 -- -- 2,434 -------- -------- -------- -------- Net earnings applicable to common shareholders $115,185 17,333 18,382 150,900 ======== ======== ======== ======== Capital expenditures $206,744 42,131 34,097 282,972 ======== ======== ======== ======== </Table> 15
16 8. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL ----------- ----------- ----------- ----------- (IN THOUSANDS) <S> <C> <C> <C> <C> SIX MONTHS ENDED JUNE 30, 2001: REVENUES Oil sales $ 310,900 56,764 120,892 488,556 Gas sales 1,030,808 131,569 5,801 1,168,178 Natural gas liquids sales 54,635 9,321 345 64,301 Other 23,943 1,690 2,081 27,714 ----------- ----------- ----------- ----------- Total revenues 1,420,286 199,344 129,119 1,748,749 ----------- ----------- ----------- ----------- COSTS AND EXPENSES Lease operating expenses 167,806 32,119 38,178 238,103 Transportation costs 30,050 5,773 -- 35,823 Production taxes 72,826 893 339 74,058 Depreciation, depletion and amortization of property and equipment 296,578 39,285 31,731 367,594 Amortization of goodwill 16,901 -- 22 16,923 General and administrative expenses 45,709 3,824 (2,643) 46,890 Interest expense 64,918 3,512 510 68,940 Reduction of carrying value of oil and gas properties -- -- 76,942 76,942 ----------- ----------- ----------- ----------- Total costs and expenses 694,788 85,406 145,079 925,273 ----------- ----------- ----------- ----------- Earnings (loss) before change in fair value of derivative instruments, income tax expense and cumulative effect of change in accounting principle 725,498 113,938 (15,960) 823,476 Change in fair value of derivative instruments (6,582) -- -- (6,582) ----------- ----------- ----------- ----------- Earnings (loss) before income tax expense and cumulative effect of change in accounting principle 718,916 113,938 (15,960) 816,894 INCOME TAX EXPENSE Current 131,087 1,910 9,895 142,892 Deferred 140,748 45,604 445 186,797 ----------- ----------- ----------- ----------- Total income tax expense 271,835 47,514 10,340 329,689 ----------- ----------- ----------- ----------- Earnings (loss) before cumulative effect of change in accounting principle 447,081 66,424 (26,300) 487,205 Cumulative effect of change in accounting principle 49,452 -- -- 49,452 ----------- ----------- ----------- ----------- Net earnings (loss) 496,533 66,424 (26,300) 536,657 Preferred stock dividends 4,868 -- -- 4,868 ----------- ----------- ----------- ----------- Net earnings (loss) applicable to common shareholders $ 491,665 66,424 (26,300) 531,789 =========== =========== =========== =========== Capital expenditures $ 796,691 109,841 112,227 1,018,759 =========== =========== =========== =========== </Table> 16
17 8. SEGMENT INFORMATION (CONTINUED) <Table> <Caption> INTER- U.S. CANADA NATIONAL TOTAL --------- --------- --------- --------- (IN THOUSANDS) <S> <C> <C> <C> <C> SIX MONTHS ENDED JUNE 30, 2000: REVENUES Oil sales $ 377,676 57,168 110,091 544,935 Gas sales 494,833 67,844 5,600 568,277 Natural gas liquids sales 62,271 8,545 100 70,916 Other 21,916 2,322 534 24,772 --------- --------- --------- --------- Total revenues 956,696 135,879 116,325 1,208,900 --------- --------- --------- --------- COSTS AND EXPENSES Lease operating expenses 157,220 25,225 35,362 217,807 Transportation costs 19,017 5,728 -- 24,745 Production taxes 41,147 524 200 41,871 Depreciation, depletion and amortization of property and equipment 284,812 32,353 20,338 337,503 Amortization of goodwill 20,681 -- 12 20,693 General and administrative expenses 42,752 4,795 1,326 48,873 Interest expense 75,355 4,996 600 80,951 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- 2,408 -- 2,408 --------- --------- --------- --------- Total costs and expenses 640,984 76,029 57,838 774,851 --------- --------- --------- --------- Earnings before income tax expense 315,712 59,850 58,487 434,049 INCOME TAX EXPENSE Current 64,326 979 7,200 72,505 Deferred 56,247 27,263 19,513 103,023 --------- --------- --------- --------- Total income tax expense 120,573 28,242 26,713 175,528 --------- --------- --------- --------- Net earnings 195,139 31,608 31,774 258,521 Preferred stock dividends 4,868 -- -- 4,868 --------- --------- --------- --------- Net earnings applicable to common shareholders $ 190,271 31,608 31,774 253,653 ========= ========= ========= ========= Capital expenditures $ 546,471 78,157 94,399 719,027 ========= ========= ========= ========= </Table> 17
18 9. COMMITMENTS AND CONTINGENCIES Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon's estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon's financial position or results of operations after consideration of recorded accruals. Environmental Matters Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon's consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information. Certain of Devon's subsidiaries acquired in the PennzEnergy merger are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of June 30, 2001, Devon's consolidated balance sheet included $7.7 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is based in large part on (i) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material. Royalty Matters More than 30 oil companies, including Devon, are involved in disputes in which it is alleged that such companies and related parties underpaid royalty, overriding royalty and working interests owners in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming that have been consolidated into one proceeding in Texas. To avoid expensive and protracted litigation, certain parties, including Devon, have entered into a global settlement agreement which provides for a settlement of all claims of all members of the settlement class. The court held a fairness hearing and issued an Amended Final Judgment approving the settlement on September 10, 1999. However, certain entities have appealed their objections to the settlement. 18
19 9. COMMITMENTS AND CONTINGENCIES (CONTINUED) Also, pending in federal court in Texas is a similar suit alleging underpaid royalties to the United States in connection with natural gas and natural gas liquids produced and sold from United States owned and/or controlled lands. The claims were filed by private litigants against Devon and numerous other producers, under the federal False Claims Act. The United States served notice of its intent to intervene as to certain defendants, but not Devon. Devon and certain other defendants are challenging the constitutionality of whether a claim under the federal False Claims Act can be maintained absent government intervention. Devon believes that it has acted reasonably and paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this litigation. As a result, Devon's monetary exposure in this suit is not expected to be material. Maersk Rig Contract In December 1997, the working interest owner partner of Pennzoil Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the PennzEnergy merger, entered into a contract with Maersk Jupiter Drilling, S.A. ("Maersk") for the provision of a rig for drilling services relative to the anticipated drilling program associated with Devon's Block 70/80 in Lake Maracaibo, Venezuela. The rig was assembled and delivered by Maersk to Lake Maracaibo where it performed an abbreviated drilling program for both Blocks 68/79 and 70/80. It is currently stacked in Lake Maracaibo. The contract, which expires October 1, 2001, provides for early termination, with a charge for such termination which is currently estimated at $42,000 per day with certain escalation factors for the balance of the term. As of June 30, 2001, Devon's consolidated balance sheet included accrued liabilities, reflected in "Other liabilities," for the expected cost to terminate/settle the contract. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such termination/settlement of the contract. 19
20 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion addresses material changes in results of operations for the three- month and six-month periods ended June 30, 2001, compared to the three-month and six-month periods ended June 30, 2000, and in financial condition since December 31, 2000. The discussion should be read in conjunction with Devon's 2000 annual report on Form 10-K. OVERVIEW Net earnings for the second quarter of 2001 were $136.4 million, or $1.03 per share. This compares to net earnings of $153.3 million, or $1.19 per share for the second quarter of 2000. Net earnings for the first half of 2001 were $536.7 million, or $4.11 per share. These compare to net earnings for the first half of 2000 of $258.5 million, or $2.00 per share. The decrease in second quarter earnings was due to the reduction of carrying value of oil and gas prices related to certain international properties, partially offset by higher average gas prices and gas production. The increase in first half earnings was due to higher natural gas prices and production. 20
21 RESULTS OF OPERATIONS Total revenues increased $76.7 million, or 12%, in the second quarter of 2001, and $539.8 million, or 45%, in the first half of 2001. This was the result of increases in the average prices of gas and NGL partially offset by lower production on a combined Boe basis. Oil, gas and NGL revenues were up $73.8 million, or 12%, for the second quarter of 2001 compared to the second quarter of 2000, and $536.9 million, or 45% for the first half of 2001 compared to the first half of 2000. The three-month and six-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 SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------------- ------------------------------ 2001 2000 CHANGE 2001 2000 CHANGE ---- ---- ------ ---- ---- ------ <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MBbls) 9,995 11,179 -11% 20,434 22,094 -8% Gas (MMcf) 108,514 106,201 +2% 220,283 209,970 +5% NGL (MBbls) 1,630 1,762 -7% 2,947 3,696 -20% Oil, Gas and NGL (MBoe)1 29,711 30,641 -3% 60,095 60,785 -1% AVERAGE PRICES Oil (Per Bbl) $23.47 24.58 -5% 23.91 24.66 -3% Gas (Per Mcf) 4.08 3.08 +32% 5.30 2.71 +96% NGL (Per Bbl) 19.61 19.03 +3% 21.82 19.19 +14% Oil, Gas and NGL (Per Boe)1 23.88 20.75 +15% 28.64 19.48 +47% ($'S IN THOUSANDS) REVENUES Oil $234,574 274,778 -15% 488,556 544,935 -10% Gas 443,014 327,460 +35% 1,168,178 568,277 +106% NGL 31,964 33,539 -5% 64,301 70,916 -9% -------- ------- --------- --------- Combined $709,552 635,777 +12% 1,721,035 1,184,128 +45% ======== ======= ========= ========= </Table> 21
22 <Table> <Caption> DOMESTIC ------------------------------------------------------------- THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------------- ------------------------------ 2001 2000 CHANGE 2001 2000 CHANGE ---- ---- ------ ---- ---- ------ <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MBbls) 6,271 7,609 -18% 12,973 15,173 -14% Gas (MMcf) 90,737 87,621 +4% 185,391 172,827 +7% NGL (MBbls) 1,459 1,590 -8% 2,600 3,350 -22% Oil, Gas and NGL (MBoe)1 22,853 23,803 -4% 46,472 47,328 -2% AVERAGE PRICES Oil (Per Bbl) $23.02 24.69 -7% 23.97 24.89 -4% Gas (Per Mcf) 4.27 3.29 +30% 5.56 2.86 +94% NGL (Per Bbl) 18.83 18.41 +2% 21.01 18.59 +13% Oil, Gas and NGL (Per Boe)1 24.48 21.22 +15% 30.05 19.75 +52% ($'S IN THOUSANDS) REVENUES Oil $144,352 187,842 -23% 310,900 377,676 -18% Gas 387,627 287,964 +35% 1,030,808 494,833 +108% NGL 27,472 29,270 -6% 54,635 62,271 -12% -------- ------- --------- --------- Combined $559,451 505,076 +11% 1,396,343 934,780 +49% ======== ======= ========= ========= </Table> <Table> <Caption> CANADA ------------------------------------------------------------- THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------------- ------------------------------ 2001 2000 CHANGE 2001 2000 CHANGE ---- ---- ------ ---- ---- ------ <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MBbls) 1,334 1,162 +15% 2,620 2,364 +11% Gas (MMcf) 15,513 16,408 -5% 30,705 32,786 -6% NGL (MBbls) 154 168 -8% 328 342 -4% Oil, Gas and NGL (MBoe)1 4,074 4,065 +0% 8,066 8,170 -1% AVERAGE PRICES Oil (Per Bbl) $21.72 23.83 -9% 21.67 24.18 -10% Gas (Per Mcf) 3.36 2.22 +51% 4.28 2.07 +107% NGL (Per Bbl) 27.25 24.82 +10% 28.42 24.99 +14% Oil, Gas and NGL (Per Boe)1 20.93 16.82 +24% 24.50 16.35 +50% ($'S IN THOUSANDS) REVENUES Oil $28,977 27,695 +5% 56,764 57,168 -1% Gas 52,104 36,496 +43% 131,569 67,844 +94% NGL 4,197 4,169 +1% 9,321 8,545 +9% -------- ------- --------- --------- Combined $85,278 68,360 +25% 197,654 133,557 +48% ======== ======= ========= ========= </Table> 22
23 <Table> <Caption> INTERNATIONAL ------------------------------------------------------------- THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------------- ------------------------------ 2001 2000 CHANGE 2001 2000 CHANGE ---- ---- ------ ---- ---- ------ <S> <C> <C> <C> <C> <C> <C> PRODUCTION Oil (MBbls) 2,390 2,408 -1% 4,841 4,557 +6% Gas (MMcf) 2,264 2,172 +4% 4,187 4,357 -4% NGL (MBbls) 17 4 +325% 19 4 +375% Oil, Gas and NGL (MBoe)(1) 2,784 2,774 +0% 5,558 5,287 +5% AVERAGE PRICES Oil (Per Bbl) $25.63 24.60 +4% 24.97 24.16 +3% Gas (Per Mcf) 1.45 1.38 +5% 1.39 1.29 +8% NGL (Per Bbl) 17.35 19.00 -9% 18.16 19.00 -4% Oil, Gas and NGL (Per Boe)(1) 23.28 22.47 +4% 22.86 21.90 +4% ($'S IN THOUSANDS) REVENUES Oil $61,245 59,241 +3% 120,892 110,091 +10% Gas 3,283 3,000 +9% 5,801 5,600 +4% NGL 295 100 +195% 345 100 +245% -------- ------- --------- --------- Combined $64,823 62,341 +4% 127,038 115,791 +10% ======== ======= ========= ========= </Table> - --------------- (1) Gas volumes are converted to Boe or MBoe 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. OIL REVENUES. Oil revenues decreased $40.2 million, or 15%, in the second quarter of 2001. Oil revenues decreased $11.1 million due to a $1.11 per barrel decrease in the average price of oil in 2001. A decrease in 2001's production of 1.2 million barrels caused oil revenues to decrease by $29.1 million. This reduction was primarily the result of certain domestic and international properties which were sold prior to the 2001 quarter but whose production was included in the 2000 quarter. Oil revenues decreased $56.4 million, or 10%, in the first half of 2001. Oil revenues decreased $15.4 million due to a $0.75 per barrel decrease in the average price of oil in 2001. A decrease in production of 1.7 million barrels, or 8%, caused oil revenues to decrease by $41.0 million. This reduction was primarily the result of certain domestic and international properties which were sold prior to the 2001 quarter but whose production was included in the 2000 quarter. GAS REVENUES. Gas revenues increased $115.6 million, or 35%, in the second quarter of 2001. Production rose 2.3 Bcf in the 2001 period, which added $7.2 million of gas revenues. A $1.00 per Mcf increase in the average gas price in the second quarter of 2001 contributed $108.4 million of the increase in gas revenues. The largest contributor to the 2001 production increase was production added as a result of domestic drilling and development in Devon's coalbed methane properties. 23
24 These domestic increases were partially offset by a decline in Canadian gas production of 0.9 Bcf, or 5% in the 2001 quarter. Natural declines and increased royalty rates, partially offset by new drilling, development and acquisitions, were the primary reasons for the production decline. The increase in gas prices from the 2000 quarter to the 2001 quarter resulted in an increase in the Canadian government's royalty percentage from 23.3% in the 2000 quarter to 26.9% in the 2001 quarter. Gross Canadian gas production, before royalties, was 21.2 Bcf in the 2001 quarter compared to 21.4 Bcf in the 2000 quarter. Gas revenues increased $599.9 million, or 106%, in the first half of 2001. Production rose 10.3 Bcf in the 2001 period, which added $27.9 million of gas revenues. A $2.59 per Mcf increase in the average gas price in the first half of 2001 contributed $572.0 million of the increase in gas revenues. The largest contributor to the 2001 production increase was production added as a result of domestic drilling and development in Devon's coalbed methane properties. These domestic increases were partially offset by a decline in Canadian gas production of 2.1 Bcf, or 6% in the first half of 2001. Natural declines and increased royalty rates, partially offset by new drilling, development and acquisitions, were the primary reasons for the production decline. The increase in gas prices from the 2000 period to the 2001 period resulted in an increase in the Canadian government's royalty percentage from 22.2% in the 2000 period to 28.0% in the 2001 period. Gross Canadian gas production, before royalties, was 42.5 Bcf in the 2001 period compared to 42.2 Bcf in the 2000 period. NGL REVENUES. NGL revenues decreased $1.6 million, or 5%, in the second quarter of 2001. An increase in the average price of $0.58 per barrel, or 3%, caused NGL revenues to increase $0.9 million in the 2001 quarter. A production decrease of 0.1 million barrels caused revenues to decrease $2.5 million. This reduction was primarily the result of certain domestic properties which were sold prior to the 2001 quarter but whose production was included in the 2000 quarter. NGL revenues decreased $6.6 million, or 9%, in the first half of 2001. An increase in the average price of $2.63 per barrel, or 14%, caused NGL revenues to increase $7.8 million in the first half of 2001. A production decrease of 0.7 million barrels caused revenues to decrease $14.4 million. The production drop was primarily the result of a temporary shutdown of a gas processing plant in the Gulf of Mexico during the first quarter of 2001, and certain domestic properties which were sold prior to the 2001 quarter but whose production was included in the 2000 quarter. 24
25 PRODUCTION AND OPERATING EXPENSES. The components of production and operating expenses are set forth in the following tables. <Table> <Caption> TOTAL ------------------------------------------------------------- THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ----------------------------- ------------------------------ 2001 2000 CHANGE 2001 2000 CHANGE ---- ---- ------ ---- ---- ------ ($'S IN THOUSANDS) ABSOLUTE <S> <C> <C> <C> <C> <C> <C> Recurring operations and maintenance expenses $113,520 108,281 +5% 229,712 211,836 +8% Well workover expenses 1,935 2,819 -31% 8,391 5,971 +41% Transportation costs 18,419 12,932 +42% 35,823 24,745 +45% Production taxes 29,549 22,473 +31% 74,058 41,871 +77% -------- ------- ------- ------- Total production and operating expenses $163,423 146,505 +12% 347,984 284,423 +22% ======== ======= ======= ======= PER BOE Recurring operations and maintenance expenses 3.82 3.54 +8% 3.82 3.48 +10% Well workover expenses 0.07 0.09 -31% 0.14 0.10 +42% Transportation costs 0.62 0.42 +47% 0.60 0.41 +46% Production taxes 0.99 0.73 +36% 1.23 0.69 +79% ----- ---- ---- ---- Total production and operating expenses $5.50 4.78 +15% 5.79 4.68 +24% ===== ==== ==== ==== </Table> Recurring operations and maintenance expenses increased $5.2 million, or 5%, in the second quarter of 2001. Recurring operations and maintenance expenses increased $17.9 million, or 8%, in the first half of 2001. These increases were primarily the result of increases in fuel and electricity costs as well as increases in many third-party field service costs. Transportation costs increased $5.5 million, or 42%, in the second quarter of 2001. Transportation costs increased $11.1 million, or 45%, in the first half of 2001. These increases were primarily due to an increase in coalbed methane gas production and increases in transportation rates. Production taxes increased $7.1 million, or 31%, in the 2001 quarter. Also, production taxes increased $32.2 million, or 77%, in the first half of 2001. 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% and 49% increase in domestic oil, gas and NGL revenues in the second quarter and first half of 2001, respectively, was a primary cause of the production tax increase. Production taxes did not increase proportionately to the increase in revenues. This was primarily due to the fact that most of the increase in domestic revenues occurred in the Rocky Mountain division which has higher production tax rates than the other domestic divisions. DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES ("DD&A"). Oil and gas property related DD&A increased $9.2 million, or 6%, from $164.5 million in the second quarter of 2000 to $173.7 million in the second quarter of 2001. Oil and gas property related DD&A expense decreased $5.0 million due to the 3% decrease in combined oil, gas and NGL production in 2001. An increase in the combined U.S., Canadian and international DD&A rate from $5.37 per Boe in the 2000 quarter to $5.85 per Boe in the 2001 quarter caused oil and gas property related DD&A to increase $14.2 million. The $0.48 increase in the 2001 rate over the 2000 rate is primarily the 25
26 result of an increase in future development costs and the disposition of certain properties during 2000, partially offset by an increase in total reserves. Oil and gas property related DD&A increased $24.4 million, or 8%, from $323.5 million in the first half of 2000 to $347.9 million in the first half of 2001. Oil and gas property related DD&A expense decreased $3.7 million due to the 1% decrease in combined oil, gas and NGL production in 2001. Additionally, an increase in the combined U.S., Canadian and international DD&A rate from $5.32 per Boe in the first half of 2000 to $5.79 per Boe in the first half of 2001 caused oil and gas property related DD&A to increase $28.1 million. The $0.47 increase in the 2001 rate over the 2000 rate is primarily the result of an increase in future development costs and the disposition of certain properties during 2000, partially offset by an increase in total reserves. Non-oil and gas property DD&A expense increased $3.3 million to $11.0 million in the second quarter of 2001 compared to $7.7 million the second quarter of 2000. Non-oil and gas property DD&A expense increased $5.6 million to $19.7 million in the first half of 2001 compared to $14.1 million in the first half of 2000. Depreciation of new non-oil and gas property and the gas pipeline and gathering system in Wyoming accounted for the increase. GENERAL AND ADMINISTRATIVE EXPENSES ("G&A"). Devon's net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full-cost method of accounting. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property's life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. The following table is a summary of G&A expenses by component for the second quarter and first half of 2001 and 2000. <Table> <Caption> THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------- ------------------ 2001 2000 2001 2000 ------- ------- ------- ------- (IN THOUSANDS) <S> <C> <C> <C> <C> Gross G&A $60,708 52,465 112,107 105,166 Capitalized G&A (22,897) (14,216) (38,790) (28,502) Reimbursed G&A (13,183) (14,226) (26,427) (27,791) ------- ------- ------- ------- Net G&A $24,628 24,023 46,890 48,873 ======= ======= ======= ======= </Table> Net G&A increased $0.6 million, or 3%, and decreased $2.0 million, or 4%, in the second quarter and first half of 2001 compared to the same periods of 2000, respectively. Gross G&A increased $8.2 million and $6.9 million, or 16% and 7%, in the second quarter and first half of 2001 compared to the same periods of 2000, respectively. The increases in gross expenses in the second quarter and first half of 2001 were primarily related to additional personnel related costs. Net G&A was reduced $8.7 million and $10.3 million in the second quarter and first half of 2001, respectively, due to an increase in the amount capitalized as part of oil and gas properties. The increase in capitalized G&A was primarily related to additional personnel related 26
27 costs and increased drilling activities. Net G&A, however, rose $1.1 million and $1.4 million in the second quarter and first half of 2001, respectively, due to a decrease in the amount of reimbursements on operated properties. The decrease in reimbursed G&A was primarily related to the disposition of certain domestic properties which were owned in the 2000 periods but which were sold prior to the 2001 periods. INTEREST EXPENSE. Interest expense decreased $6.5 million and $12.0 million, or 16% and 15%, in the second quarter and first half of 2001, respectively, due to a decrease in the average debt balance outstanding. The decrease in the average debt balance in both the second quarter and first half of 2001 was primarily attributable to the repayment of long-term debt from excess cash flow. The annualized interest rates for the 2001 periods were increased as a result of the adoption of Financial Accounting Standards Board Statement of Financial Accounting Standards No. 133 ("SFAS No. 133") effective January 1, 2001. Pursuant to SFAS No. 133, the debentures that are exchangeable into shares of Chevron Corporation common stock were revalued as of August 17, 1999. This is the date the debentures were assumed as part of the PennzEnergy merger. Under SFAS No. 133, the total fair value of the debentures was allocated between the interest-bearing debt and the option that is embedded in the debentures. Accordingly, the debt portion of the debentures was reduced by $139.6 million as of August 17, 1999. This discount is being accreted in interest expense, which has raised the effective interest rate on the debentures to 7.76% in the second quarter and first six months of 2001 compared to 4.92% recorded prior to 2001. The accretion in the second quarter and first six months of 2001 was $3.1 million and $6.1 million, respectively. The following schedule includes the components of interest expense for the second quarter and first half of 2001 and 2000. <Table> <Caption> THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------- ----------------- 2001 2000 2001 2000 ---- ---- ---- ---- (IN THOUSANDS) <S> <C> <C> <C> <C> Interest based on debt outstanding $32,007 41,346 64,408 82,044 Amortization of discounts (premiums) 2,042 (1,023) 4,027 (1,946) Facility and agency fees 267 1,132 544 1,822 Amortization of capitalized loan costs 301 447 601 894 Capitalized interest (620) (846) (1,314) (1,542) Other 405 (181) 674 (321) ------- ------ ------ ------ Total interest expense $34,402 40,875 68,940 80,951 ======= ====== ====== ====== </Table> DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT. Until mid-January 2000, Devon's Canadian subsidiary Northstar Energy Corporation had certain fixed-rate senior notes which were 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 issued to the date of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent balance of the debt were required to be included in determining net earnings for the 27
28 period in which the exchange rate changed. In mid-January 2000, the U.S. dollar denominated notes were retired prior to maturity with cash on hand and borrowings under Devon's long-term credit facilities. The Canadian-to-U.S. dollar exchange rate dropped slightly in January 2000 prior to the debt retirement. As a result, $2.4 million of expense was recognized in the first half of 2000. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES. During the second quarter of 2001, Devon elected to discontinue operations in Malaysia, Qatar and on certain properties in Brazil. Accordingly, during the second quarter of 2001, Devon recorded a $76.9 million charge associated with the impairment of these properties. The after-tax effect of this reduction was $62.1 million. CHANGE IN FAIR VALUE OF DERIVATIVE INSTRUMENTS. As a result of the adoption of SFAS No. 133 effective January 1, 2001, all derivatives are included on the balance sheet at their fair value. The $7.5 million gain and $6.6 million loss included in the second quarter and first six months of 2001, respectively, principally represent the change in the fair value of derivatives that do not qualify as hedges. The change is primarily the result of changes in the fair value of the option embedded in the debentures exchangeable into shares of Chevron Corporation common stock. INCOME TAXES. During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate in the second quarter of 2001 was 43% compared to 40% in the second quarter of 2000. The higher effective tax rate in the second quarter of 2001 was primarily related to the reduction of carrying value of oil and gas properties. The estimated effective tax rate was 40% in both the first half of 2001 and the first half of 2000. 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 June 30, 2001, were approximately $208 million of net operating loss 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 2001 and 2007 and minimum tax credits which have no expiration. Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2001 and 2006. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, Devon's management believes that future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expirations. 28
29 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE. At the time of adoption of SFAS No. 133, Devon recorded a cumulative-effect-type adjustment to net earnings for a $49.5 million gain related to the fair value of derivatives that do not qualify as hedges. This gain included $46.2 million related to the option embedded in the debentures that are exchangeable into shares of Chevron 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 I, Item 1 included elsewhere herein. CAPITAL EXPENDITURES. Approximately $1.0 billion was spent in the first six months of 2001 for capital expenditures. This total includes $0.5 billion for the acquisition of oil and gas properties and $0.5 billion for the drilling or development of oil and gas properties. Approximately $0.7 billion was spent for capital expenditures in the first half of 2000. This total includes $0.2 billion for the acquisition of oil and gas properties and $0.5 billion for the drilling or development of oil and gas properties. CAPITAL RESOURCES AND LIQUIDITY. Net cash provided by operating activities ("operating cash flow") continued to be the primary source of capital and liquidity in the first half of 2001. Operating cash flow in the first half of 2001 was $1.1 billion, compared to $0.7 billion in the first half of 2000. The increase in operating cash flow in the first half of 2001 was primarily caused by the rise in revenues, partially offset by increased expenses, as discussed earlier in this section. Devon used its operating cash flow and additional borrowings, net of repayments, of to fund its capital expenditures and increase cash and cash equivalents by almost $250 million during the first half of 2001. As of July 31, 2001, Devon had approximately $785 million available under its $1 billion credit facilities. IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED. In July 2001, the FASB issued Statement No. 141, Business Combinations, and Statement No. 142, Goodwill and Other Intangible Assets. Statement 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001 as well as all purchase method business combinations completed after June 30, 2001. Statement 141 also specifies criteria intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill. Statement 142 will require that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of Statement 142. Statement 142 will also require that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. Devon is required to adopt the provisions of Statement 141 immediately, and the provisions of Statement 142 effective January 1, 2002. Furthermore, any goodwill and any intangible asset determined to have an indefinite useful life that are acquired in a purchase 29
30 business combination completed after June 30, 2001 will not be amortized, but will continue to be evaluated for impairment in accordance with the appropriate pre-Statement 142 accounting literature. Goodwill and intangible assets acquired in business combinations completed before July 1, 2001 will continue to be amortized prior to the adoption of Statement 142. Statement 141 will require upon adoption of Statement 142, that Devon evaluate its existing goodwill that was acquired in a prior purchase business combination. In connection with the transitional goodwill impairment evaluation, Statement 142 will require Devon to perform an assessment of whether there is an indication that goodwill is impaired as of the date of adoption. To accomplish this Devon must identify its reporting units and determine the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill, to those reporting units as of the date of adoption. Devon will then have up to six months from the date of adoption to determine the fair value of each reporting unit and compare it to the reporting unit's carrying amount. To the extent a reporting unit's carrying amount exceeds its fair value, an indication exists that the reporting unit's goodwill may be impaired and Devon must perform the second step of the transitional impairment test. In the second step, Devon must compare the implied fair value of the reporting unit's goodwill, determined by allocating the reporting unit's fair value to all of it assets (recognized and unrecognized) and liabilities in a manner similar to a purchase price allocation in accordance with Statement 141, to its carrying amount, both of which would be measured as of the date of adoption. This second step is required to be completed as soon as possible, but no later than the end of the year of adoption. Any transitional impairment loss will be recognized as the cumulative effect of a change in accounting principle in Devon's statement of operations. As of the date of adoption, Devon expects to have unamortized goodwill in the amount of $261 million which will be subject to the transition provisions of Statements 141 and 142. Amortization expense related to goodwill was $41.3 million and $16.9 million for the year ended December 31, 2000 and the six months ended June 30, 2001, respectively. Devon has not assessed the impact of adopting these Statements on Devon's financial statements at the date of this report, including whether any transitional impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. Also in July 2001, the FASB issued Statement No. 143, Accounting for Asset Retirement Obligations. Statement 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 Statement 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." It is expected that many companies will use a valuation technique such as expected present value to estimate fair value. The asset retirement cost equal to the fair value of the retirement obligation is to be capitalized as part of the cost of the related long-lived asset and allocated to expense using a systematic and rational method. Devon will be required to adopt Statement 143 effective January 1, 2003 using a cumulative 30
31 effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. Devon currently records estimated costs of dismantlement, removal, site reclamation, and other similar activities as part of depreciation, depletion, and amortization and does not record a separate liability for such amounts. Devon has not completed the assessment of the impact that adoption of Statement No. 143 will have on its consolidated financial statements. However, Devon expects the amounts for capitalized oil and gas property costs and asset retirement obligations will increase. 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 2000 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of Devon's potential exposure to market risks, including commodity price risk, interest rate risk and foreign currency risk. As of June 30, 2001, there have been no material changes in Devon's market risk exposure from that disclosed in the 2000 Form 10-K. 31
32 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS None ITEM 2. CHANGES IN SECURITIES None ITEM 3. DEFAULTS UPON SENIOR SECURITIES None ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (a) Devon's annual meeting of shareholders was held in Oklahoma City, Oklahoma at 10:00 a.m. local time, on Thursday May 17, 2001. (b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as directors as listed in the proxy statement and all nominees were elected. (c) Out of a total of 129,413,681 shares of Devon's common stock outstanding and entitled to vote, 116,844,380 shares were present at the meeting in person or by proxy, representing approximately 90 percent of the total outstanding. The only matter voted upon at the meeting was the election of three directors to serve on Devon's board of directors until the 2004 annual meeting of shareholders. The vote tabulation with respect to each nominee was as follows: <Table> <Caption> AUTHORITY NOMINEE FOR WITHHELD ------- --- --------- <S> <C> <C> Thomas F. Ferguson 115,994,004 850,376 David M. Gavrin 116,054,793 789,587 Michael E. Gellert 113,178,278 3,666,102 </Table> 32
33 ITEM 5. OTHER INFORMATION None ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits required by Item 601 of Regulation S-K are as follows: Exhibit No. 10.1.2 Second Amendment to U.S. Credit Agreement dated as of June 27, 2001, among Registrant, Bank of America, N.A., individually and as administrative agent, and the U.S. Lenders party to the Original Agreement. 10.2.2 Second Amendment to Canadian Credit Agreement dated as of June 27, 2001, among Northstar Energy Corporation, Bank of America Canada, individually and as administrative agent, and the Canadian Lenders party to the Original Agreement. (b) Reports on Form 8-K. None 33
34 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: August 14, 2001 /s/ Danny J. Heatly --------------------------------- Danny J. Heatly Vice President - Accounting 34
35 INDEX TO EXHIBITS <Table> <Caption> Exhibit Page - ------- ---- <S> <C> <C> 10.1.2 Second Amendment to U.S. Credit Agreement dated as of June 27, 2001, among Registrant, Bank of America, N.A., individually and as administrative agent, and the U.S. Lenders party to the Original Agreement...........................................................36 10.2.2 Second Amendment to Canadian Credit Agreement dated as of June 27, 2001, among Northstar Energy Corporation, Bank of America Canada, individually and as administrative agent, and the Canadian Lenders party to the Original Agreement.....................................52 </Table> 35