================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------- FORM 10-Q/A QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001 Commission file number 1-12534 ---------- NEWFIELD EXPLORATION COMPANY (Exact name of registrant as specified in its charter) Delaware 72-1133047 (State or other jurisdiction (I.R.S. employer of incorporation or organization) identification number) 363 N. Sam Houston Parkway E. Suite 2020 Houston, Texas 77060 (Address and Zip Code of principal executive offices) Registrant's telephone number, including area code: (281) 847-6000 ---------- 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 [ ] As of November 1, 2001, there were 43,990,178 shares of the Registrant's Common Stock, par value $0.01 per share, outstanding. ================================================================================ EXPLANATORY NOTE The Company is re-filing its third quarter 2001 10-Q to add the following sentence to Note 2, "Oil and Gas Properties" and under "General" in Management's Discussion and Analysis; "No consideration of the value of production associated with proved oil and gas properties which has been hedged against fluctuations in oil and gas prices in financial markets can be attributed to the value of such properties in determining the limitation on net capitalized costs." No other changes have been made to the Company's consolidated financial statements. TABLE OF CONTENTS PART I Page ---- Item 1. Financial Statements: Consolidated Balance Sheet as of September 30, 2001 and December 31, 2000 ..................................... 1 Consolidated Statement of Income for the three and nine months ended September 30, 2001 and 2000 ......................... 2 Consolidated Statement of Cash Flows for the nine months ended September 30, 2001 and 2000 ............. 3 Consolidated Statement of Stockholders' Equity for the nine months ended September 30, 2001 .............. 4 Notes to Consolidated Financial Statements ................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations .......................... 15 PART II Item 6. Exhibits and Reports on Form 8-K ............................... 24 -ii- NEWFIELD EXPLORATION COMPANY CONSOLIDATED BALANCE SHEET (In thousands of dollars, except share data) (Unaudited) September 30, December 31, 2001 2000 ------------- ------------ ASSETS Current assets: Cash and cash equivalents ...................... $ 33,195 $ 18,451 Accounts receivable-oil and gas ................ 103,641 147,643 Inventories .................................... 10,796 7,572 Commodity derivatives .......................... 75,001 -- Other current assets ........................... 13,347 5,891 ------------- ------------ Total current assets ......................... 235,980 179,557 ------------- ------------ Oil and gas properties (full cost method, of which $161,656 at September 30, 2001 and $106,783 at December 31, 2000 were excluded from amortization) .................................. 2,434,784 1,589,150 Less-accumulated depreciation, depletion and amortization ................................... (961,427) (756,243) ------------- ------------ 1,473,357 832,907 ------------- ------------ Furniture, fixtures and equipment, net ........... 7,049 4,028 Commodity derivatives ............................ 16,254 -- Other assets ..................................... 10,260 6,758 ------------- ------------ Total assets ................................. $ 1,742,900 $ 1,023,250 ============= ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable ............................... $ 7,101 $ 10,209 Other accrued liabilities ...................... 162,817 128,190 Advances from joint owners ..................... 2,085 2,661 Commodity derivatives .......................... 4,719 -- ------------- ------------ Total current liabilities .................... 176,722 141,060 ------------- ------------ Other liabilities ................................ 7,926 6,030 Commodity derivatives ............................ 3,117 -- Long-term debt ................................... 393,620 133,711 Deferred taxes ................................... 258,603 79,244 ------------- ------------ Total long-term liabilities .................. 663,266 218,985 ------------- ------------ Company-obligated, mandatorily redeemable, convertible preferred securities of Newfield Financial Trust I ............................... 143,750 143,750 ------------- ------------ Commitments and contingencies .................... -- -- Stockholders' equity: Preferred stock ($0.01 par value, 5,000,000 shares authorized, no shares issued) ......... -- -- Common stock ($0.01 par value, 100,000,000 shares authorized; 44,792,809 and 42,625,764 shares issued at September 30, 2001 and December 31, 2000, respectively) ......... 448 426 Additional paid-in capital ....................... 361,663 286,811 Treasury stock (at cost, 859,431 and 18,463 shares at September 30, 2001 and December 31, 2000, respectively) ............................ (25,751) (399) Unearned compensation ............................ (8,535) (6,201) Accumulated other comprehensive income (loss) - Foreign currency translation adjustment ........ (8,106) (4,644) Commodity derivatives .......................... 37,917 -- Retained earnings ................................ 401,526 243,462 ------------- ------------ Total stockholders' equity ................... 759,162 519,455 ------------- ------------ Total liabilities and stockholders' equity ... $ 1,742,900 $ 1,023,250 ============= ============ The accompanying notes to consolidated financial statements are an integral part of this financial statement. -1- NEWFIELD EXPLORATION COMPANY CONSOLIDATED STATEMENT OF INCOME (In thousands, except per share data) (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, ------------------------ ------------------------ 2001 2000 2001 2000 ---------- ---------- ---------- ---------- Oil and gas revenues .................................. $ 183,259 $ 150,431 $ 593,332 $ 362,957 ---------- ---------- ---------- ---------- Operating expenses: Lease operating ..................................... 30,245 17,780 73,819 47,520 Production and other taxes .......................... 3,311 1,802 15,892 3,801 Transportation ...................................... 1,325 1,568 4,150 4,671 Depreciation, depletion and amortization ............ 74,259 50,989 206,982 138,382 Ceiling test write-down ............................. -- 503 -- 503 General and administrative (includes non-cash stock compensation of $729 and $767 for the three months ended September 30, 2001 and 2000, respectively, and $2,027 and $2,262 for the nine months ended September 30, 2001 and 2000, respectively) ..................................... 12,135 8,803 35,359 22,901 ---------- ---------- ---------- ---------- Total operating expenses .......................... 121,275 81,445 336,202 217,778 ---------- ---------- ---------- ---------- Income from operations ................................ 61,984 68,986 257,130 145,179 Other income (expenses): Interest income ..................................... 316 580 1,458 1,502 Interest expense .................................... (6,897) (3,815) (20,520) (11,552) Capitalized interest ................................ 2,354 1,374 6,508 3,938 Dividends on convertible preferred securities of Newfield Financial Trust I .......... (2,336) (2,336) (7,008) (7,008) Unrealized commodity derivative income .............. 11,101 -- 15,262 -- ---------- ---------- ---------- ---------- 4,538 (4,197) (4,300) (13,120) ---------- ---------- ---------- ---------- Income before income taxes ............................ 66,522 64,789 252,830 132,059 Income tax provision: Current ............................................. 473 8,447 30,961 22,894 Deferred ............................................ 23,073 12,790 59,011 21,014 ---------- ---------- ---------- ---------- 23,546 21,237 89,972 43,908 ---------- ---------- ---------- ---------- Income before cumulative effect of change in accounting principles ............................... 42,976 43,552 162,858 88,151 Cumulative effect of change in accounting principles, net of tax Adoption of SAB 101 ............................... -- -- -- (2,360) Adoption of SFAS 133 .............................. -- -- (4,794) -- ---------- ---------- ---------- ---------- Net income ............................................ $ 42,976 $ 43,552 $ 158,064 $ 85,791 ========== ========== ========== ========== Earnings per share Basic - Income before cumulative effect of change in accounting principles ................. $ 0.97 $ 1.02 $ 3.67 $ 2.09 Cumulative effect of change in accounting principles ........................... -- -- (0.11) (0.06) ---------- ---------- ---------- ---------- Net income ........................................ $ 0.97 $ 1.02 $ 3.56 $ 2.03 ========== ========== ========== ========== Diluted - Income before cumulative effect of change in accounting principles ................. $ 0.91 $ 0.95 $ 3.42 $ 1.97 Cumulative effect of change in accounting principles ........................... -- -- (0.10) (0.05) ---------- ---------- ---------- ---------- Net income ........................................ $ 0.91 $ 0.95 $ 3.32 $ 1.92 ========== ========== ========== ========== Weighted average number of shares outstanding for basic earnings per share ....................... 44,219 42,493 44,344 42,260 ========== ========== ========== ========== Weighted average number of shares outstanding for diluted earnings per share ..................... 48,798 47,366 49,014 47,158 ========== ========== ========== ========== The accompanying notes to consolidated financial statements are an integral part of this financial statement. -2- NEWFIELD EXPLORATION COMPANY CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands) (Unaudited) Nine Months Ended September 30, ---------------------------- 2001 2000 ------------ ------------ Cash flows from operating activities: Net income .................................. $ 158,064 $ 85,791 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ........................ 206,982 138,382 Deferred taxes ............................ 59,011 21,014 Stock compensation ........................ 2,027 2,262 Unrealized commodity derivative income .... (15,262) -- Cumulative effect of change in accounting principles ................... 4,794 2,360 Ceiling test write-down ................... -- 503 ------------ ------------ 415,616 250,312 Changes in assets and liabilities, net of business acquired: (Increase) decrease in accounts receivable- oil and gas ............................. 72,640 (28,341) Increase in inventories ................... (4,142) (4,992) Increase in other current assets .......... (8,421) (810) (Increase) decrease in other assets ....... (8,212) 477 Increase (decrease) in accounts payable and accrued liabilities ................. (5,797) 28,592 Increase (decrease) in advances from joint owners ............................ (576) 5,845 Increase (decrease) in other liabilities .. 1,983 (3,536) ------------ ------------ Net cash provided by operating activities .................. 463,091 247,547 ------------ ------------ Cash flows from investing activities: Acquisition of Lariat Petroleum, net of cash acquired .................... (264,089) -- Additions to oil and gas properties ....... (417,806) (287,781) Additions to furniture, fixtures and equipment ............................... (3,468) (1,097) ------------ ------------ Net cash used in investing activities ... (685,363) (288,878) ------------ ------------ Cash flows from financing activities: Proceeds from borrowings .................. 1,110,000 158,000 Repayments of borrowings .................. (1,025,000) (120,000) Proceeds from issuance of senior notes .... 174,879 -- Proceeds from issuance of common stock, net ............................... 1,795 5,875 Purchases of treasury stock ............... (25,352) -- ------------ ------------ Net cash provided by financing activities ............................ 236,322 43,875 ------------ ------------ Effect of exchange rate changes on cash and cash equivalents .......................... 694 (432) ------------ ------------ Increase in cash and cash equivalents ........... 14,744 2,112 Cash and cash equivalents, beginning of period .. 18,451 41,841 ------------ ------------ Cash and cash equivalents, end of period ........ $ 33,195 $ 43,953 ============ ============ The accompanying notes to consolidated financial statements are an integral part of this financial statement. -3- NEWFIELD EXPLORATION COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (In thousands, except share data) (Unaudited) Accumulated Common Stock Additional Treasury Stock Other ------------------ Paid-in ----------------- Unearned Retained Comprehensive Shares Amount Capital Shares Amount Compensation Earnings Income (Loss) ---------- ------ ---------- ------- ------- ------------ -------- ------------- Balance, December 31, 2000 ..................... 42,625,764 $ 426 $ 286,811 (18,463) $ (399) $ (6,201) $243,462 $ (4,644) Issuance of common stock .................. 2,047,077 21 69,628 Purchase of treasury stock .................. Issuance of restricted stock, less amortization of $589 ................ 119,968 1 4,359 (3,771) Treasury Stock ............. (840,968) (25,352) Cancellation of restricted stock ...... Amortization of stock compensation ........... 1,437 Tax benefit from exercise of stock options .......... 865 Comprehensive Income: Net income ............... 158,064 Foreign currency translation adjustment ............. (3,462) Cumulative effect of accounting change, net of tax of $39,964 .. (74,218) Reclassification adjustments for settled contracts, net of tax of $24,242 ................ 45,021 Changes in fair value of outstanding hedging positions, net of tax of $36,138 ................ 67,114 Total Comprehensive Income ........... ---------- ------ ---------- -------- -------- ------------ -------- ------------- Balance, September 30, 2001 ...................... 44,792,809 $ 448 $ 361,663 (859,431) $(25,751) $ (8,535) $401,526 $ 29,811 ========== ====== ========== ======== ======== ============ ======== ============= Total Stockholders' Equity ------------- Balance, December 31, 2000 ..................... $ 519,455 Issuance of common stock .................. 69,649 Purchase of treasury stock .................. Issuance of restricted stock, less amortization of $589 ................ 589 Treasury Stock ............. (25,352) Cancellation of restricted stock ...... Amortization of stock compensation ........... 1,437 Tax benefit from exercise of stock options .......... 865 Comprehensive Income: Net income ............... 158,064 Foreign currency translation adjustment ............. (3,462) Cumulative effect of accounting change, net of tax of $39,964 .. (74,218) Reclassification adjustments for settled contracts, net of tax of $24,242 ................ 45,021 Changes in fair value of outstanding hedging positions, net of tax of $36,138 ................ 67,114 ------------- Total Comprehensive Income ........... 192,519 ------------- Balance, September 30, 2001 ...................... $ 759,162 ============= The accompanying notes to consolidated financial statements are an integral part of this financial statement. -4- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (1) Accounting Policies Basis of Presentation Unless the context otherwise requires, references to the "Company" include Newfield Exploration Company and its subsidiaries. All significant intercompany balances and transactions have been eliminated. The unaudited consolidated financial statements of the Company reflect, in the opinion of management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the Company's consolidated financial statements for the periods presented. The consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and therefore do not include all disclosures required for financial statements prepared in conformity with generally accepted accounting principles. Interim period results are not necessarily indicative of results of operations or cash flows for a full year. Certain reclassifications have been made to prior year's reported amounts in order to conform to the current year presentation. In the fourth quarter of 2000 we adopted SEC Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements." SAB No. 101 requires us to report crude oil inventory associated with our Australian offshore operations at lower of cost or market, which is a change from our historical policy of recording such inventory at market value on the balance sheet date, net of estimated costs to sell. The cumulative effect of the change from the acquisition date of our Australian operations in July 1999 through December 31, 1999 is a reduction in net income of $2.36 million,or $0.05 per diluted share, and is shown as the cumulative effect of change in accounting principle on our consolidated statement of income for the nine month period ended September 30, 2000. The adoption of SAB No. 101 does not affect any period prior to our acquisition in Australia. As a result of the adoption of Emerging Issues Task Force (EITF) No. 00-10, "Accounting for Shipping and Handling Fees and Costs," we have reclassified to operating expenses, for all periods presented, third party costs incurred to transport production to our sales point. Such costs previously were recorded as a reduction of the related revenues. This reclassification had no effect on previously reported net income. Approximately $1.6 million and $4.7 million were reclassified pursuant to EITF No. 00-10 for the three and nine month periods ended September 30, 2000, respectively. These consolidated financial statements and the notes thereto should be read in conjunction with the Company's consolidated financial statements and the notes thereto for the year ended December 31, 2000 included in the Company's Current Report on Form 8-K dated October 4, 2001. Accounting Changes On January 1, 2001, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138. See Note 6, "Commodity Derivative Instruments and Hedging Activities." On June 29, 2001, the Financial Accounting Standards Board ("FASB") approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Under SFAS 141, all business combinations should be accounted for using the purchase method of accounting; use of the pooling-of-interests method is prohibited. The provisions of the statement will apply to all business combinations initiated after June 30, 2001. SFAS No. 142 will apply to all acquired intangible assets whether acquired singly, as part of a group, or in a business combination. The statement will supersede Accounting Principles Board (APB) Opinion No. 17, "Intangible Assets," but continue provisions in APB Opinion No. 17 related to internally developed intangible assets. Adoption of SFAS 142 will result in ceasing amortization of goodwill. All of the provisions of the statement should be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company does not expect the adoption of these standards to have a material effect on its consolidated financial statements. The FASB recently issued SFAS 143, "Accounting for Asset Retirement Obligations." This statement changes the method of accruing for costs associated with the retirement of fixed assets (e.g. oil & gas production facilities, etc.) that an entity is legally obligated to incur. Implementation of this standard is required no later than January 1, 2003, with earlier application encouraged. The Company is currently assessing the impact of this standard. In October 2001, the FASB approved SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which clarified certain implementation issues arising from SFAS No. 121, "Accounting for Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of." This standard is effective for the Company on January 1, 2002. The Company is currently assessing the impact of this standard. -5- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued) (Unaudited) Earnings per Share Basic earnings per common share (EPS) is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities were exercised for or converted into common stock. The following is a calculation of basic and diluted weighted average shares outstanding for each of the three and nine month periods ended September 30, 2001 and 2000. Three Months Ended Nine Months Ended September 30, September 30, ------------------- ------------------- 2001 2000 2001 2000 -------- -------- -------- -------- (In thousands, except per share data): Income (numerator): Income - basic .......................... $ 42,976 $ 43,552 $158,064 $ 85,791 After tax dividends on convertible trust preferred securities ........... 1,518 1,518 4,555 4,555 -------- -------- -------- -------- Income - diluted ........................ $ 44,494 $ 45,070 $162,619 $ 90,346 ======== ======== ======== ======== Shares (denominator): Shares - basic .......................... 44,219 42,493 44,344 42,260 Dilution effect of stock options outstanding at end of period .......... 656 950 747 975 Dilution effect of convertible trust preferred securities ............ 3,923 3,923 3,923 3,923 -------- -------- -------- -------- Shared - diluted ........................ 48,798 47,366 49,014 47,158 ======== ======== ======== ======== Earnings per share: Basic .................................. $ 0.97 $ 1.02 $ 3.56 $ 2.03 Diluted ................................ $ 0.91 $ 0.95 $ 3.32 $ 1.92 The calculation of shares outstanding for diluted EPS above does not include the effect of outstanding stock options to purchase 1,026,000 and 66,500 shares for the three months ended September 30, 2001 and 2000, respectively, and 850,000 and 86,500 for the nine months ended September 30, 2001 and 2000, respectively, because to do so would have been antidilutive. -6- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) Hedging On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires enterprises to recognize all derivatives as either assets or liabilities on their balance sheet and measure those instruments at fair value. See Note 6 - "Commodity Derivative Instruments and Hedging Activities." For all periods prior to January 1, 2001, the Company accounted for commodity price hedging contracts in accordance with SFAS No. 80. Pursuant to SFAS No. 80, gains and losses on these contracts were recognized in revenue in the period in which the underlying production was delivered. Hedging contracts were measured for correlation at both the inception of the contract and on an ongoing basis. If a contract ceased to meet the criteria for deferral accounting, any subsequent gains or losses were recognized in revenue. If a hedging contract was terminated prior to maturity, resulting gains and losses were deferred until the hedged item was recognized in revenue. Neither the hedging contracts nor the unrealized gains or losses on these contracts were recognized in the financial statements. (2) Oil and Gas Properties The Company uses the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into cost centers that are established on a country-by-country basis. For each cost center, the net capitalized costs are amortized on a unit-of-production method based on proved reserves. For each cost center, the net capitalized costs of oil and gas properties are limited to the lower of unamortized cost or the cost center ceiling, defined as the sum of the present value (10% per annum discount rate) of estimated future net revenues from proved reserves, based on the oil and gas prices in effect on the balance sheet date; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. No consideration of the value of production associated with proved oil and gas properties which has been hedged against fluctuations in oil and gas prices in financial markets can be attributed to the value of such properties in determining the limitation on net capitalized costs. If net capitalized costs of oil and gas properties exceed the cost center ceiling, the Company is subject to a ceiling test writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings. If required, it would reduce earnings and impact stockholder's equity in the period of occurrence and result in lower depreciation, depletion and amortization expense in future periods. The risk that the Company will be required to writedown the carrying value of its oil and gas properties increases when oil and gas prices are depressed or if the Company has substantial downward revisions in its estimated proved reserves. Application of these rules during periods of relatively low oil or gas prices, even if temporary, increases the probability of a ceiling test writedown. Based on oil and gas prices in effect on September 30, 2001 ($1.90 per MMBtu for gas and $23.37 per barrel for oil), the unamortized cost of the Company's domestic oil and gas properties exceeded the cost center ceiling from its proved oil and gas reserves. However, the Company was not required to adjust its net capitalized costs downward because oil and gas prices increased sufficiently after September 30, 2001 so that its unamortized costs did not exceed the cost center ceiling. (3) Acquisitions On January 23, 2001, the Company acquired all of the outstanding capital stock of Lariat Petroleum, Inc. ("Lariat") by merging Lariat with and into Newfield Exploration Mid-Continent Inc., a wholly owned subsidiary of the Company. The total consideration for the acquisition was approximately $333 million, consisting of $68 million in Newfield stock and $265 million in cash funded through the Company's credit facility. The Company also assumed debt and certain other obligations of Lariat. -7- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) In February 2000, the Company acquired interests in three producing gas fields in South Texas for approximately $137 million in cash. The acquisitions have been accounted for as purchases and, accordingly, income and expenses for Lariat and from the South Texas properties have been included in the Company's statement of income from the date of purchase. The unaudited pro forma results of operations assuming that such acquisitions occurred on January 1 of the respective periods are as follow (in thousands, except per share amounts): Nine Months Ended September 30, ------------------------ 2001 2000 ---------- ---------- Pro forma Pro forma (Unaudited) Revenue .......................................... $ 598,974 $ 414,867 Income from operations ........................... 258,271 158,064 Income before cumulative effect of change in accounting principles ....................... 162,640 87,989 Cumulative effect of change in accounting principles ..................................... (4,794) (2,360) Net income ....................................... 157,846 85,629 Basic earnings per common share before cumulative effect of change in accounting principle ...................................... $ 3.67 $ 1.99 Basic earnings per common share .................. $ 3.56 $ 1.94 Diluted earnings per common share before cumulative effect of change in accounting principle ...................................... $ 3.41 $ 1.87 Diluted earnings per common share ................ $ 3.31 $ 1.84 The pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisitions taken place at the beginning of the periods presented or future results of operations. (4) Contingencies The Company has been named as a defendant in certain lawsuits arising in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position, cash flows or results of operations of the Company. -8- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) (5) Geographic Information Other United States Australia International Total ------------- ------------ ------------- ------------ (In thousands) Three months ended September 30, 2001 Oil and gas revenues ........................ $ 174,126 $ 9,133 $ -- $ 183,259 Operating expenses: Lease operating ........................... 26,097 4,148 -- 30,245 Production and other taxes ................ 3,357 (46) -- 3,311 Transportation ............................ 1,325 -- -- 1,325 Depreciation, depletion and amortization ............................ 72,075 2,184 -- 74,259 Allocated income taxes .................... 24,945 854 -- ------------ ------------ ------------ Net income from oil and gas operations ....................... $ 46,327 $ 1,993 $ -- ============ ============ ============ General and administrative (inclusive of stock compensation) ......................... 12,135 ------------ Total operating expenses .......... 121,275 ------------ Income from operations ...................... 61,984 Interest expense and dividends, net ......................... (6,563) Unrealized commodity derivative income ................................. 11,101 ------------ Income before income taxes .................. $ 66,522 ============ Total long-lived assets ..................... $ 1,437,434 $ 11,425 $ 24,498 $ 1,473,357 ============ ============ ============ ============ Additions to long-lived assets .............. $ 157,563 $ 4,391 $ 3,146 $ 165,100 ============ ============ ============ ============ Three months ended September 30, 2000 Oil and gas revenues ........................ $ 138,635 $ 11,796 $ -- $ 150,431 Operating expenses: Lease operating ........................... 14,919 2,861 -- 17,780 Production and other taxes ................ 1,263 539 -- 1,802 Transportation ............................ 1,568 -- -- 1,568 Depreciation, depletion and amortization ........................... 49,378 1,611 -- 50,989 Ceiling test write-down ................... -- -- 503 503 Allocated income taxes .................... 25,027 2,036 -- -- ------------ ------------ ------------ Net income from oil and gas operations ....................... $ 46,480 $ 4,749 $ (503) ============ ============ ============ General and administrative (inclusive of stock compensation) ......................... 8,803 ------------ Total operating expenses .......... 81,445 ------------ Income from operations ...................... 68,986 Interest expense and dividends, net ......................... (4,197) ------------ Income before income taxes .................. $ 64,789 ============ Total long-lived assets ..................... $ 772,116 $ 10,082 $ 13,351 $ 795,549 ============ ============ ============ ============ Additions to long-lived assets .............. $ 54,715 $ (2,464) $ 1,910 $ 54,161 ============ ============ ============ ============ -9- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) Other United States Australia International Total ------------- ------------ ------------- ------------ (In thousands) Nine months ended September 30, 2001 Oil and gas revenues ................... $ 568,324 $ 25,008 $ -- $ 593,332 Operating expenses: Lease operating ...................... 62,890 10,929 -- 73,819 Production and other taxes ........... 12,217 3,675 -- 15,892 Transportation ....................... 4,150 -- -- 4,150 Depreciation, depletion and amortization ....................... 201,850 5,132 -- 206,982 Allocated income taxes ............... 100,526 1,582 -- ------------- ------------ ------------- Net income from oil and gas operations .................. $ 186,691 $ 3,690 $ -- ============= ============ ============ General and administrative (inclusive of stock compensation) .................... 35,359 ------------ Total operating expenses ..... 336,202 ------------ Income from operations ................. 257,130 Interest expense and dividends, net .................... (19,562) Unrealized commodity derivative income ............................ 15,262 ------------ Income before income taxes ............. $ 252,830 ============ Total long-lived assets ................ $ 1,437,434 $ 11,425 $ 24,498 $ 1,473,357 ============= ============ ============= ============ Additions to long-lived assets ......... $ 831,641 $ 5,739 $ 8,254 $ 845,634 ============= ============ ============= ============ Nine months ended September 30, 2000 Oil and gas revenues ................... $ 331,588 $ 31,369 $ -- $ 362,957 Operating expenses: Lease operating ...................... 38,445 9,075 -- 47,520 Production and other taxes ........... 3,252 549 -- 3,801 Transportation ....................... 4,671 -- -- 4,671 Depreciation, depletion and amortization ...................... 133,695 4,687 -- 138,382 Ceiling test write-down .............. -- -- 503 503 Allocated income taxes ............... 53,034 5,117 -- ------------- ------------ ------------- Net income from oil and gas operations .................. $ 98,491 $ 11,941 $ (503) ============= ============ ============= General and administrative (inclusive of stock compensation) .................... 22,901 ------------ Total operating expenses ..... 217,778 ------------ Income from operations ................. 145,179 Interest expense and dividends, net .................... (13,120) ------------ Income before income taxes ............. $ 132,059 ============ Total long-lived assets ................ $ 772,116 $ 10,082 $ 13,351 $ 795,549 ============= ============ ============= ============ Additions to long-lived assets ......... $ 274,850 $ 11,395 $ 3,424 $ 289,669 ============= ============ ============= ============ -10- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) (6) Commodity Derivative Instruments and Hedging Activities The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133, an amendment of FASB Statement No. 133," and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133," on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, on January 1, 2001, the Company recorded as cumulative effect adjustments a loss of $74.2 million (net of tax of $40.0 million) in accumulated other comprehensive loss and a loss of $4.8 million (net of tax of $2.6 million) in 2001 earnings. In addition, the adoption resulted in the recognition of $17.7 million of derivative assets and $139.3 million of derivative liabilities on the balance sheet on January 1, 2001. The Company maintains a commodity-price risk management strategy that utilizes derivative instruments in order to hedge against the variability in cash flows associated with the forecasted sale of its oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counter parties to such instruments will be unable to meet the financial terms of such contracts. All derivatives are recognized on the balance sheet at their fair value. On the date that the Company enters into a derivative contract, it designates the derivative as a hedge of the variability in cash flows associated with the forecasted sale of its oil and gas production. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in other comprehensive income (loss), until earnings are affected by the variability of cash flows of the hedged transaction (e.g., until the sale of the Company's oil and gas production is recorded in earnings). Such gains or losses are reported in oil and gas revenues on the consolidated statement of income. For the nine months ended September 30, 2001, the Company had the following activity in the "Commodity derivatives" component of accumulated other comprehensive income (loss) (in thousands): Cumulative effect of accounting change, net of tax ......... $(74,218) Reclassification adjustments for settled contracts, net of tax ............................................... 45,021 Change in fair value of outstanding hedging positions, net of tax ............................................... 67,114 -------- $ 37,917 ======== The Company expects that within the next twelve months it will reclassify to earnings $50.4 million in after tax gains out of the net $37.9 million in after tax gains recorded in accumulated other comprehensive income at September 30, 2001. -11- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) Any hedge ineffectiveness (which represents the amount by which the changes in the fair value of the derivative exceed the variability in the cash flows of the forecasted transaction) is recorded in current-period earnings. For the three and nine month periods ended September 30, 2001, the Company recorded an unrealized gain of $11.1 million and $15.3 million, respectively, under the income statement caption "Unrealized commodity derivative income" representing the net of the ineffective portion of the Company's commodity derivative positions during the three and nine month periods ended September 30, 2001 as well as the change in the time value component of the option contracts used in the Company's hedging strategy. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to the specific forecasted sale of oil or gas at its physical location. The Company also formally assesses (both at the hedge's inception and on an ongoing basis) whether the derivatives that are used in hedging transactions have been highly effective in offsetting changes in the cash flows of hedged items and whether those derivatives may be expected to remain highly effective in future periods. If it is determined that a derivative is not (or has ceased to be) highly effective as a hedge, the Company will discontinue hedge accounting prospectively. The gain or loss on the derivative will remain in accumulated other comprehensive income or loss and will be reclassified into earnings when the forecasted transaction affects earnings. If hedge accounting is discontinued and the derivative remains outstanding, the Company will carry the derivative at its fair value on the balance sheet, recognizing all subsequent changes in the fair value in current-period earnings. Hedge accounting was not discontinued during the period for any hedging instruments. SFAS 133 is complex and subject to a potentially wide range of interpretation in its application. There are currently several issues before the FASB and the potential exists for additional issues to be brought under its review. If subsequent FASB interpretations of SFAS 133 are different than the Company's current interpretation, it is possible that the application of SFAS 133 on the Company's financial statements will be modified. NATURAL GAS. As of September 30, 2001, the Company had entered into the commodity derivative instruments set forth in the table below as a cash flow hedge of the forecasted sale of its U.S. Gulf Coast natural gas production for 2001 through 2003. NYMEX CONTRACT PRICE PER MMBTU ---------------------------------------------------------------------------- COLLARS ------------------------------------------- FLOORS CEILINGS FLOOR CONTRACTS SWAPS --------------------- --------------------- ---------------------- VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED FAIR MARKET PERIOD MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE VALUE(1) ----------------------------- --------- --------- ----------- --------- ---------- --------- ----------- --------- -------------- October 2001 -- December 2001 Price Swap Contracts....... 15,170 $3.86 -- -- -- -- -- -- $23.9 million Collar Contracts........... 5,140 -- $3.50-$4.75 $3.92 $4.50-$6.00 $5.16 -- -- $ 9.1 million Floor Contracts ........... 800 -- -- -- -- -- $3.37-$3.66 $3.51 $(0.9 million) January 2002 -- March 2002 Price Swap Contracts....... 9,050 $3.85 -- -- -- -- -- -- $ 9.2 million Collar Contracts........... 8,790 -- $3.50-$4.25 $3.79 $4.90-$9.95 $5.81 -- -- $ 9.4 million April 2002 -- June 2002 Price Swap Contracts ...... 8,600 $3.52 -- -- -- -- -- -- $ 6.3 million Collar Contracts........... 4,200 -- $3.75-$4.00 $3.98 $4.80-$6.00 $5.33 -- -- $ 5.3 million July 2002 -- September 2002 Price Swap Contracts ...... 1,200 $3.68 -- -- -- -- -- -- $ 0.9 million Collar Contracts........... 4,200 -- $3.75-$4.00 $3.98 $4.80-$6.00 $5.32 -- -- $ 5.0 million October 2002 -- December 2002 Price Swap Contracts....... 1,200 $3.86 -- -- -- -- -- -- $ 0.9 million Collar Contracts........... 3,300 -- $4.00 $4.00 $4.80-$6.10 $5.27 -- -- $ 3.7 million January 2003 -- December 2003 Price Swap Contracts....... 1,825 $3.32 -- -- -- -- -- -- $ 0.2 million ---------- (1) Except for October 2001 hedging contracts, fair market value is calculated using prices derived from NYMEX futures contract prices existing at September 30, 2001. Because October 2001 NYMEX futures contracts expired on September 26, 2001, the fair market value of October 2001 hedging contracts represents the actual settlement value of such contracts. -12- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) (Unaudited) In connection with the acquisition of Lariat in January 2001, the Company assumed certain commodity derivative instruments and designated them as cash flow hedges of the forecasted natural gas sales of the Company's production in Oklahoma. The table below presents the outstanding derivative instruments as of September 30, 2001. CONTRACT PRICE PER MMBTU ------------------------------------ SWAPS COLLARS VOLUME IN (WEIGHTED ------------------------ FAIR MARKET PERIOD MMMBTUS AVERAGE) FLOORS CEILINGS VALUE(1) -------------------------------------------- --------- --------- ----------- ---------- -------------- October 2001 -- December 2001 Price Swap Contracts...................... 2,420 $4.11 -- -- $ 4.5 million January 2002 -- December 2002 Price Swap Contracts...................... 3,650 $2.62 -- -- $(0.5 million) January 2003 -- March 2003 Price Swap Contracts...................... 900 $2.61 -- -- $(0.5 million) ---------- (1) Except for October 2001 hedging contracts, fair market value is calculated using prices derived from NYMEX futures contract prices existing at September 30, 2001. Because October 2001 NYMEX futures contracts expired on September 26, 2001, the fair market value of October 2001 hedging contracts represents the actual settlement value of such contracts. OIL AND CONDENSATE. As of September 30, 2001, the Company had entered into commodity derivative instruments set forth in the table below as a cash flow hedge of the forecasted sale of its U.S. Gulf Coast oil production for 2001 through 2003. NYMEX CONTRACT PRICE PER BBL ------------------------------------------------------------------------------ COLLARS --------------------------------------------- FLOORS CEILINGS FLOOR CONTRACTS SWAPS ---------------------- ---------------------- ---------------------- (WEIGHTED WEIGHTED WEIGHTED WEIGHTED FAIR MARKET PERIOD BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE VALUE(1) ----------------------------- ------- --------- ------------- -------- ------------- -------- ------------- -------- -------------- October 2001 -- December 2001 Price Swap Contracts....... 570,400 $23.78 -- -- -- -- -- -- $ -- million Collar Contracts........... 345,000 -- $24.00-$25.25 $24.77 $27.30-$30.75 $29.26 -- -- $ 0.6 million Floor Contracts............ 400,200 -- -- -- -- -- $21.15-$26.00 $23.85 $ 0.7 million January 2002 -- March 2002 Price Swap Contracts....... 180,000 $24.92 -- -- -- -- -- -- $ 0.2 million Collar Contracts........... 818,500 -- $21.00-$25.00 $23.64 $25.75-$30.75 $28.21 -- -- $ 0.9 million Floor Contracts............ 135,000 -- -- -- -- -- $21.15 $21.15 $ 0.1 million April 2002 -- June 2002 Price Swap Contracts....... 182,000 $24.92 -- -- -- -- -- -- $ 0.2 million Collar Contracts........... 728,000 -- $21.00-$25.00 $23.45 $25.75-$30.75 $27.95 -- -- $ 0.9 million Floor Contracts............ 136,500 -- -- -- -- -- $21.15 $21.15 $ 0.1 million July 2002 -- September 2002 Price Swap Contracts....... 184,000 $24.92 -- -- -- -- -- -- $ 0.3 million Collar Contracts........... 713,000 -- $21.00-$25.00 $23.50 $26.75-$30.75 $28.60 -- -- $ 0.9 million Floor Contracts............ 138,000 -- -- -- -- -- $21.15 $21.15 $ 0.2 million October 2002 -- December 2002 Price Swap Contracts....... 184,000 $24.92 -- -- -- -- -- -- $ 0.4 million Collar Contracts........... 583,000 -- $21.00-$25.00 $23.50 $26.75-$30.75 $28.86 -- -- $ 0.8 million Floor Contracts............ 138,000 -- -- -- -- -- $21.15 $21.15 $ 0.2 million January 2003 -- March 2003 Price Swap Contracts....... 180,000 $24.92 -- -- -- -- -- -- $ 0.4 million Collar Contracts........... 90,000 -- $21.00 $21.00 $27.50 $27.50 -- -- $(0.1 million) Floor Contracts............ 135,000 -- -- -- -- -- $21.15 $21.15 $ 0.3 million April 2003 -- June 2003 Collar Contracts........... 91,000 -- $21.00 $21.00 $27.50 $27.50 -- -- $(0.1 million) ---------- (1) Except for October 2001 hedging contracts, fair market value is calculated using prices derived from NYMEX futures contract prices existing at September 30, 2001. Because October 2001 NYMEX futures contracts expired on September 20, 2001, the fair market value of October 2001 hedging contracts represents the actual settlement value of such contracts. -13- NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -(Continued) (Unaudited) With respect to any particular swap transaction, the counter party is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price for such transaction, and the Company is required to make payment to the counter party if the settlement price for any settlement period is greater than the swap price for such transaction. For any particular collar transaction, the counter party is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counter party if the settlement price for any settlement period is above the ceiling price of such transaction. For any particular floor transaction, the counter party is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor transaction. (7) Treasury Stock On May 4, 2001, the Company announced that its Board of Directors authorized the expenditure of up to $50 million to repurchase shares of the Company's common stock. As of September 30, 2001, the Company had repurchased 823,000 shares of its common stock under this program for total consideration of $24.7 million, an average of $29.97 per share. Additional repurchases may be effected from time to time in accordance with applicable securities laws, through solicited or unsolicited transactions in the market or in privately negotiated transactions. No limit was placed on the duration of the repurchase program. Subject to applicable securities laws, such purchases will be at times and in amounts as the Company deems appropriate. As of November 1, 2001, no shares had been purchased during the fourth quarter of 2001. -14- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL As an independent oil and gas producer, our revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas, oil and condensate, which are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital and on the quantities of oil and gas reserves that may be economically produced. Our results of operations and cash flows may vary significantly from quarter to quarter as a result of development operations, commodity prices, the curtailment of production in association with work over and recompletion activities and the incurrence of expenses related thereto and the timing of crude oil offloadings from inventory in Australia. Consequently, quarterly results of operations and cash flows may not be indicative of results for the full year. We use the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into cost centers that are established on a country-by-country basis. For each cost center, at the end of each quarter, the net capitalized costs of oil and gas properties are limited to the lower of unamortized cost or the cost center ceiling, defined as the sum of the present value (10% discount rate) of estimated future net revenues from proved reserves, based on period-end oil and gas prices; plus the cost of properties not being amortized, if any; plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less related income tax effects. No consideration of the value of production associated with proved oil and gas properties which has been hedged against fluctuations in oil and gas prices in financial markets can be attributed to the value of such properties in determining the limitation on net capitalized costs. If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings. If required, it would reduce earnings and impact stockholders' equity in the period of occurrence and result in lower depreciation, depletion and amortization expense in future periods. The risk that we will be required to writedown the carrying value of our oil and gas properties increases when oil and gas prices are depressed or if we have substantial downward revisions in our estimated proved reserves. Application of these rules during periods of relatively low oil or gas prices, even if temporary, increases the probability of a ceiling test writedown. Based on oil and gas prices in effect on September 30, 2001 ($1.90 per MMBtu for gas and $23.37 per barrel for oil), the unamortized cost of our domestic oil and gas properties exceeded the cost center ceiling from our proved oil and gas reserves. However, we were not required to adjust our net capitalized costs downward because oil and gas prices increased sufficiently after September 30, 2001 so that our unamortized costs did not exceed the cost center ceiling. Because of the volatility of oil and gas prices and, in particular, the relatively low recent prices for oil and gas, no assurance can be given that we will not experience a ceiling test writedown in future quarterly periods. If, for purposes of determining the net present of our domestic proved reserves at September 30, 2001, we had used prices of $2.25 per MMBtu for gas and $21.00 per barrel for oil, we would have recorded a domestic ceiling test writedown of as much as $200 million in the third quarter. As recently as October 25, 2001, relevant benchmark prices were $2.68 per MMBtu for gas (Gas Daily-Henry Hub) and $21.61 per barrel for oil (Platt's - WTI at Cushing). We adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" on January 1, 2001. Please see the discussion in Note 6, "Commodity Derivative Instruments and Hedging Activities," to our consolidated financial statements appearing earlier in this report. In the fourth quarter of 2000 we adopted SEC Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements." SAB No. 101 requires us to report crude oil inventory associated with our Australian offshore operations at lower of cost or market, which is a change from our historical policy of recording such inventory at market value on the balance sheet date, net of estimated costs to sell. The cumulative effect of the change from the acquisition date of our Australian operations in July 1999 through December 31, 1999 is a reduction in net income of $2.36 million, or $0.05 per diluted share, and is shown as the cumulative effect of change in accounting principle on our consolidated statement of income for the nine month period ended September 30, 2000. The adoption of SAB No. 101 does not affect any period prior to our acquisition in Australia. -15- As a result of the adoption of Emerging Issues Task Force (EITF) No. 00-10, "Accounting for Shipping and Handling Fees and Costs," we have reclassified to operating expenses, for all periods presented, third party costs incurred to transport production to our sales point. Such costs previously were recorded as a reduction of the related revenues. This reclassification had no effect on previously reported net income. Approximately $1.6 million and $4.7 million were reclassified pursuant to EITF No. 00-10 for the three and nine month periods ended September 30, 2000, respectively. On June 29, 2001, the Financial Accounting Standards Board (FASB) approved its proposed SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Under SFAS No. 141, all business combinations should be accounted for using the purchase method of accounting; use of the pooling-of-interests method is prohibited. The provisions of the statement will apply to all business combinations initiated after June 30, 2001. SFAS No. 142 will apply to all acquired intangible assets whether acquired singly, as part of a group or in a business combination. The statement will supersede Accounting Principles Board (APB) Opinion No. 17, "Intangible Assets," but continues in APB Opinion No. 17 related to internally developed intangible assets. Adoption of SFAS No. 142 will result in ceasing amortization of goodwill. All of the provisions of the statement should be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. We do not expect the adoption of these standards to have a material effect on our consolidated financial statements. The FASB recently issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement changes the method of accruing for costs associated with the retirement of fixed assets (e.g. oil & gas production facilities, etc.) that an entity is legally obligated to incur. Implementation of this standard is required no later than January 1, 2003, with earlier application encouraged. The Company is currently assessing the impact of this standard. In October 2001, the FASB approved SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which clarified certain implementation issues arising from SFAS No. 121, "Accounting for Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of." This standard is effective for the Company on January 1, 2002. The Company is currently assessing the impact of this standard. Explanation of some commonly used oil and gas terms can be found under the caption "Commonly Used Oil and Gas Terms" at the end of Management's Discussion and Analysis. -16- RESULTS OF OPERATIONS The following table presents information about our oil and gas production and realized prices. Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ----------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- PRODUCTION: UNITED STATES Natural gas (Bcf) ................. 35.0 27.9 101.2 77.5 Oil and condensate (MBbls) ........ 1,418 1,190 4,034 3,064 Total (Bcfe) ...................... 43.5 35.1 125.4 95.9 AUSTRALIA(1) Oil and condensate (MBbls) ........ 360 372 941 1,084 Total (Bcfe) ...................... 2.2 2.2 5.7 6.5 TOTAL Natural gas (Bcf) ................. 35.0 27.9 101.2 77.5 Oil and condensate (MBbls) ........ 1,778 1,562 4,975 4,148 Total (Bcfe) ...................... 45.7 37.3 131.1 102.4 AVERAGE REALIZED PRICES:(2) UNITED STATES Natural gas (per Mcf) ............. $ 3.94 $ 3.86 $ 4.59 $ 3.29 Oil and condensate (per Bbl) ...... 24.52 24.66 24.55 23.57 AUSTRALIA(2) Oil and condensate (per Bbl) ...... $ 25.40 $ 31.68 $ 26.58 $ 28.95 TOTAL Natural gas (per Mcf) ............. $ 3.94 $ 3.86 $ 4.59 $ 3.29 Oil and condensate (per Bbl) ...... 24.70 26.33 24.93 24.97 ---------- (1) Represents oil and condensate sold during the period rather than production. (2) As discussed above, as the result of the adoption of EITF No. 00-10, we have reclassified third party transportation costs as operating expenses. Previously, such costs were recorded as a reduction of the related revenue. However, for purposes of this table, average realized prices for natural gas and oil and condensate are presented net of all applicable transportation expenses, which reduces the realized price of natural gas by $0.02 and $0.04 for the three months ended September 30, 2001 and 2000, respectively, and by $0.03 and $0.05 for the nine months ended September 30, 2001 and 2000, respectively. The realized price of oil and condensate is reduced by $0.28 and $0.26 for the three months ended September 30, 2001 and 2000, respectively, and by $0.27 and $0.30 for the nine months ended September 30, 2001 and 2000, respectively. Average realized prices include the effect of hedges. PRODUCTION NATURAL GAS. The increase in gas production was primarily related to the acquisition of producing properties in South Texas in February 2000, the acquisition of Lariat Petroleum in January 2001, development projects in the Gulf of Mexico and the success of our drilling program. Gains in production were partially offset by natural declines from other producing properties. CRUDE OIL AND CONDENSATE. The increase in oil and condensate production is mainly due to the acquisition of Lariat Petroleum in January 2001 and development projects at Vermilion 215 and Eugene Island 198/199/202. These increases were offset during the nine month period ended September 30, 2001 by the decrease in reported Australian crude oil production caused by the timing of liftings of crude oil from our two FPSOs. -17- EFFECT OF HEDGING ON REALIZED PRICES Average Realized Prices Ratio of ------------------------- Hedged to With Without Non-Hedged Hedge Hedge Price(1) ---------- ---------- ---------- Natural Gas Three months ended September 30, 2000..... $ 3.86 $ 4.46 87% Three months ended September 30, 2001..... $ 3.94 $ 2.83 139% Nine months ended September 30, 2000...... $ 3.29 $ 3.58 92% Nine months ended September 30, 2001...... $ 4.59 $ 4.72 97% Crude Oil and Condensate Three months ended September 30, 2000..... $26.33 $31.29 84% Three months ended September 30, 2001..... $24.70 $25.30 98% Nine months ended September 30, 2000...... $24.97 $29.28 85% Nine months ended September 30, 2001...... $24.93 $26.15 95% ---------- (1) The ratio is determined by dividing the realized price (which includes the effects of hedging) by the price that otherwise would have been realized without hedging activities. OPERATING EXPENSES The following table presents information about our operating expenses for the three months ended September 30, 2001 and 2000. UNIT OF PRODUCTION (PER MCFE) AMOUNT (IN MILLIONS) --------------------------------- --------------------------------- Three Months Ended Three Months Ended September 30, Percentage September 30, Percentage -------------------- Increase -------------------- Increase 2001 2000 (Decrease) 2001 2000 (Decrease) -------- -------- ---------- -------- -------- ---------- UNITED STATES Lease operating ............................... $ 0.60 $ 0.42 43% $ 26,097 $ 14,904 75% Production and other taxes .................... 0.08 0.04 100% 3,357 1,278 163% Transportation ................................ 0.03 0.04 (25)% 1,325 1,568 (15)% Depreciation, depletion and amortization ...... 1.66 1.41 18% 72,075 49,378 46% General and administrative (exclusive of stock compensation) ......................... 0.25 0.22 14% 10,971 7,670 43% AUSTRALIA Lease operating ............................... $ 1.92 $ 1.29 49% $ 4,148 $ 2,876 44% Production and other taxes .................... (0.02) 0.23 (109)% (46) 524 (109)% Transportation ................................ -- -- -- -- -- -- Depreciation, depletion and amortization ...... 1.01 0.72 40% 2,184 1,611 36% General and administrative (exclusive of stock compensation) ......................... 0.20 0.16 25% 435 366 19% TOTAL Lease operating ............................... $ 0.66 $ 0.48 38% $ 30,245 $ 17,780 70% Production and other taxes .................... 0.07 0.05 40% 3,311 1,802 84% Transportation ................................ 0.03 0.04 (25)% 1,325 1,568 (15)% Depreciation, depletion and amortization ...... 1.63 1.37 19% 74,259 50,989 46% General and administrative (exclusive of stock compensation) ......................... 0.25 0.22 14% 11,406 8,036 42% Operating expenses during the three month period ended September 30, 2001 were impacted by the following: - The per unit of production increase in domestic lease operating expense reflects higher oilfield service and related costs in the Gulf of Mexico and a non-recurring workover of a well at South Marsh Island 160 of $5.5 million. The 49% increase in our Australian lease operating expense per Mcfe is due mainly to several non-routine maintenance operations on our FPSOs during the third quarter of 2001. - The significant increase in production and other taxes in the third quarter of 2001 is primarily due to our expanding onshore Gulf Coast operations and the acquisition of Lariat Petroleum in January 2001 offset by a lower natural gas price environment during the third quarter of 2001. The decrease in production and other taxes in Australia is due to revised estimates of such taxes during the third quarter of 2001 as a result of changes in the timing and amount of anticipated future capital expenditures in Australia. - The increase in our domestic depreciation, depletion and amortization rate is primarily the result of increases in the cost of drilling goods and services, platform and facilities construction, industry transportation costs, exploration drilling and the completion of several higher cost wells. - The increase in domestic general and administrative expense for the third quarter of 2001 is due primarily to an increase in salaries for our growing workforce. -18- The following table presents information about our operating expenses for the nine months ended September 30, 2001 and 2000. UNIT OF PRODUCTION (PER MCFE) AMOUNT (IN MILLIONS) -------------------------------- -------------------------------- Nine Months Ended Nine Months Ended September 30, Percentage September 30, Percentage ------------------- Increase ------------------- Increase 2001 2000 (Decrease) 2001 2000 (Decrease) -------- -------- ---------- -------- -------- ---------- UNITED STATES Lease operating ............................... $ 0.50 $ 0.40 25% $ 62,890 $ 38,430 64% Production and other taxes .................... 0.10 0.03 233% 12,217 3,267 274% Transportation ................................ 0.03 0.05 (40)% 4,150 4,671 (11)% Depreciation, depletion and amortization ...... 1.61 1.39 16% 201,850 133,695 51% General and administrative (exclusive of stock compensation) ......................... 0.26 0.21 24% 32,463 20,207 61% AUSTRALIA Lease operating ............................... $ 1.94 $ 1.40 38% $ 10,929 $ 9,090 20% Production and other taxes .................... 0.65 0.08 713% 3,675 534 588% Transportation ................................ -- -- -- -- -- -- Depreciation, depletion and amortization ...... 0.91 0.72 26% 5,132 4,687 9% General and administrative (exclusive of stock compensation) ......................... 0.15 0.07 114% 869 432 101% TOTAL Lease operating ............................... $ 0.56 $ 0.46 22% $ 73,819 $ 47,520 55% Production and other taxes .................... 0.12 0.04 200% 15,892 3,801 318% Transportation ................................ 0.03 0.05 (40)% 4,150 4,671 (11)% Depreciation, depletion and amortization ...... 1.58 1.35 17% 206,982 138,382 50% General and administrative (exclusive of stock compensation) ......................... 0.25 0.20 25% 33,332 20,639 62% Operating expenses during the nine month period ended September 30, 2001 were impacted by the following: - The per unit of production increase in domestic lease operating expense reflects higher oilfield service and related costs in the Gulf of Mexico and a non-recurring workover of a well at South Marsh Island 160 of $5.5 million. The 38% increase in our Australian lease operating expense per Mcfe is due mainly to several non-routine maintenance operations on our FPSOs during the first nine months 2001 and a decrease in the volume of liftings of crude oil from the FPSOs, which resulted in increased expenses and lower production. - The significant increase in production and other taxes in the nine months ended September 30, 2001 is primarily due to our expanding onshore Gulf Coast operations, the acquisition of Lariat Petroleum in January 2001 and a higher natural gas price environment overall during the first nine months of 2001. The increase in production and other taxes in Australia is due to revised estimates of such taxes in 2000 as a result of changes in the timing of anticipated future capital expenditures in Australia. - The increase in our domestic depreciation, depletion and amortization rate is primarily the result of increases in the cost of drilling goods and services, platforms and facilities construction, industry transportation costs and the completion of several higher cost wells. - The increase in domestic general and administrative expense for the nine months ended September 30, 2001 is due primarily to an increase in performance based pay and our growing workforce. Performance based compensation excluding stock compensation expense, as a component of general and administrative expense, increased from $8.4 million, or $0.08 per Mcfe, for the nine months ended September 30, 2000, to $12.3 million or $0.09 per Mcfe, for the nine months ended September 30, 2001. The increase in performance based compensation is a result of higher earnings during the first nine months of 2001 as compared to the same period of 2000. Performance based pay is limited by profitability. The significant increase in general and administrative expense on a unit of production basis in Australia is due to the timing of liftings from the FPSOs during the first nine months of 2001 as compared to the same period of 2000. -19- INTEREST EXPENSE AND DIVIDENDS We incur interest expense on our $125 million principal amount 7.45% Senior Notes due 2007, our $175 million principal amount 7 5/8% Senior Notes due 2011 and on borrowings under our reserve-based revolving credit facility and money market credit lines. Outstanding borrowings under the credit facility and money market lines of credit may vary significantly from period to period. We pay dividends on the 6.5% convertible trust preferred securities we issued in August 1999. Three Months Ended Nine Months Ended September 30, September 30, -------------------- -------------------- 2001 2000 2001 2000 -------- -------- -------- -------- (In millions) Gross interest expense ................. $ 6.9 $ 3.8 $ 20.5 $ 11.5 Capitalized interest ................... (2.3) (1.4) (6.5) (3.9) -------- -------- -------- -------- Net interest expense ................... 4.6 2.4 14.0 7.6 Dividends on preferred securities ...... 2.3 2.3 7.0 7.0 -------- -------- -------- -------- Total interest expense and dividends ... $ 6.9 $ 4.7 $ 21.0 $ 14.6 ======== ======== ======== ======== Our higher total interest expense for the three and nine month period ended September 30, 2001 is the result of borrowings in January 2001 to partially finance the acquisition of Lariat Petroleum. At September 30, 2001, borrowings under our credit facility and money market lines of credit were $94 million. UNREALIZED COMMODITY DERIVATIVE INCOME As a result of our adoption of SFAS No. 133 effective January 1, 2001, we are now required to record all derivative instruments on the balance sheet at fair value. The $11.1 million and $15.3 million unrealized income for the three and nine months ended September 30, 2001, respectively, represent the net of the ineffective portion of our commodity derivative hedge positions and the change in the time value component of the option contracts used in our hedging strategy. TAXES The effective tax rate for the three and nine month periods ended September 30, 2001 was 35% and 36%, respectively, as compared to 33% and 33% for the comparable periods in 2000. The effective tax rates were slightly greater than the statutory tax rate in 2001 as a result of state income taxes associated with the acquisition of Lariat Petroleum. LIQUIDITY AND CAPITAL RESOURCES WORKING CAPITAL. We had a working capital surplus of $59.3 million at September 30, 2001. This compares to a working capital surplus of $38.1 million at December 31, 2000. Working capital balances may fluctuate from quarter to quarter to the extent we increase or decrease borrowings under our revolving credit facility. CAPITAL RESOURCES. Historically, we have funded our oil and gas activities through cash flow from operations, equity capital, public debt and bank borrowings. DEBT. The banks participating in our facility have committed to lend the Company up to $425 million. The amount available under the facility is subject to a calculated borrowing base determined by banks holding 75% of the aggregate commitments, which is reduced by the aggregate outstanding principal amount of any senior notes issued by us (currently $300 million). The borrowing base is currently $510 million and is redetermined at least semi-annually. No assurances can be given that the banks will not elect to redetermine the borrowing base in the future. The facility contains restrictions on the payment of dividends and the incurrence of debt as well as other customary covenants and restrictions. The facility matures in January 2004. We also have money market lines of credit with various banks in an amount limited by the credit facility to $40 million. At September 30, 2001, we had outstanding borrowings under the credit facility of $70 million and $24 million of outstanding borrowings under the money market lines of credit. Consequently, at September 30, 2001, we had approximately $155 million of available capacity under our credit arrangements. -20- CASH FLOW FROM OPERATIONS. Our net cash flow from operations for the nine months ended September 30, 2001 increased 66% over the comparable period of 2000 to $415.6 million. This increase in cash flow is primarily due to higher production volumes, significantly higher realized prices and changes in working capital. CAPITAL EXPENDITURES. We made capital expenditures of $740.5 million in the first nine months of 2001. This includes $80.8 million for exploration, $252.2 million for exploitation and development projects and $407.5 million for property acquisitions, including the $333 million paid for Lariat Petroleum. We have budgeted $108 million for capital spending for the remainder of 2001. Approximately $33 million has been budgeted for domestic exploration projects and $38 million for domestic exploitation and development drilling and the construction of platforms, facilities and pipelines. International spending is estimated at $7 million for the remainder of 2001. Acquisitions are opportunistic and are generally not budgeted under our capital program. We continue to pursue attractive acquisition opportunities, however, the timing, size and purchase price of acquisitions are unpredictable. Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which proved properties are acquired. HEDGING We enter into various commodity price hedging contracts with respect to a portion of our anticipated future natural gas and crude oil production. During 2000, approximately 45% of our equivalent production was subject to hedge positions. As of November 1, 2001, approximately 66% of our anticipated production for 2001 was or is subject to hedge positions. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counter parties will be unable to meet the financial terms of such transactions. Such contracts are accounted for as derivatives in accordance with SFAS No. 133. Please see the discussion in Note 6, "Commodity Derivative Instruments and Hedging Activities," to our consolidated financial statements appearing earlier in this report. Historically, we have entered into hedging arrangements with respect to a portion of our anticipated future production offshore and onshore near the Gulf Coast. In connection with our acquisition of Lariat Petroleum in January 2001, we assumed natural gas hedges entered into by Lariat with respect to a portion Of its anticipated future production in Oklahoma. Please see the tables in Note 6, "Commodity Derivative Instruments and Hedging Activities," to our consolidated financial statements appearing earlier in this report for a description of our hedging contracts as of September 30, 2001 and the fair value of those contracts as of that date. In addition to the hedging contracts described in Note 6, we have entered into several contracts after September 30, 2001 for both our natural gas and crude and condensate production. We continue to evaluate additional hedging transactions for the remainder of 2001 and future years. NATURAL GAS. Subsequent to September 30, 2001, we have entered into the commodity derivative instruments set forth in the table below as cash flow hedges of the forecasted sale of our U.S. Gulf Coast natural gas production for 2001 through 2003. NYMEX CONTRACT PRICE PER MMBTU -------------------------------------------------------------------------------- COLLARS --------------------------------------------- FLOORS CEILINGS FLOOR CONTRACTS SWAPS --------------------- --------------------- --------------------- VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED PERIOD MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE ----------------------------- --------- --------- ----------- -------- ----------- -------- --------- -------- October 2001 -- December 2001 Price Swap Contracts....... 1,250 $2.75 -- -- -- -- -- -- Collar Contracts........... 1,000 -- $2.50 $2.50 $3.30 $3.30 -- -- Floor Contracts ........... 1,000 -- -- -- -- -- $2.85 $2.85 January 2002 -- March 2002 Collar Contracts........... 8,250 -- $2.50-$2.85 $2.72 $3.30-$3.56 $3.41 -- -- Floor Contracts ........... 3,000 -- -- -- -- -- $2.85 $2.85 April 2002 -- June 2002 Price Swap Contracts ...... 3,250 $2.76 -- -- -- -- -- -- Collar Contracts........... 4,000 -- $2.50-$3.00 $2.88 $3.30-$4.00 $3.71 -- -- Floor Contracts ........... 1,000 -- -- -- -- -- $2.85 $2.85 January 2003 -- December 2003 Price Swap Contracts....... 7,800 $3.55 -- -- -- -- -- -- Collar Contracts........... 2,400 -- $3.50 $3.50 $3.90 $3.90 -- -- -21- OIL AND CONDENSATE. Subsequent to September 30, 2001, we have entered into commodity derivative instruments set forth in the table below as cash flow hedges of the forecasted sale of our U.S. Gulf Coast oil production for 2002. NYMEX CONTRACT PRICE PER BBL --------------------------------------------------------------------------------- COLLARS ------------------------------------------ FLOORS CEILINGS FLOOR CONTRACTS SWAPS ------------------- ------------------- ------------------- (WEIGHTED WEIGHTED WEIGHTED WEIGHTED PERIOD BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE ----------------------------- ------ --------- ----- -------- ----- -------- ----- -------- January 2002 -- March 2002 Price Swap Contracts....... 90,000 $22.20 -- -- -- -- -- -- April 2002 -- June 2002 Price Swap Contracts ...... 91,000 $22.20 -- -- -- -- -- -- July 2002 -- September 2002 Price Swap Contracts ...... 92,000 $22.20 -- -- -- -- -- -- October 2002 -- December 2002 Price Swap Contracts....... 61,000 $22.20 -- -- -- -- -- -- STOCK REPURCHASE PROGRAM On May 4, 2001, we announced that our Board of Directors authorized the expenditure of up to $50 million to repurchase shares of our common stock. We purchased 311,000 shares in the third quarter of 2001 under this program for total consideration of $8.3 million, an average of $26.69 per share. Through September 30, 2001, we had purchased 823,000 shares for total consideration of $24.7 million, an average of $29.97 per share. Additional repurchases may be effected from time to time in accordance with applicable securities laws, through solicited or unsolicited transactions in the market or in privately negotiated transactions. No limit was placed on the duration of the repurchase program. Subject to applicable securities laws, purchases will be at times and in amounts as we deem appropriate. As of November 1, 2001, no shares had been purchased during the fourth quarter of 2001. ESTIMATED OPERATING AND FINANCIAL DATA; OPERATING ACTIVITIES We continue to maintain our home page located at www.newfld.com. In conjunction with our web page, we also maintain our electronic publication entitled @NFX. @NFX will be periodically published to provide updates on our current operating activities. @NFX also includes our latest publicly announced estimates of expected production volumes, costs and expenses for the then current quarter. All recent additions of @NFX are available on our web page. To receive @NFX directly by e-mail, please forward your e-mail address to pmcknight@newfld.com or visit our web page and sign up. FORWARD LOOKING INFORMATION. Certain of the statements set forth in this report regarding planned capital expenditures, drilling plans, other capital activities and the financing of capital expenditures are forward looking and are based upon assumptions and anticipated results that are subject to numerous uncertainties. Actual results may vary significantly from those anticipated due to many factors, including drilling results, oil and gas prices, industry conditions, the prices of goods and services, the availability of drilling rigs and other support services, the availability of capital resources and other factors described in our annual report on Form 10-K for the year ended December 31, 2000. In addition, the drilling of oil and gas wells and the production of hydrocarbons are subject to governmental regulations and operating risks. -22- COMMONLY USED OIL AND GAS TERMS Below are explanations of some commonly used terms in the oil and gas business. Basis risk. The risk associated with the sales point price for oil or gas production varying from the reference (or settlement) price for a particular hedging transaction. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons. Bcf. Billion cubic feet. Bcfe. Billion cubic feet equivalent, determined by using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit. MBbls. One thousand barrels of crude oil or other liquid hydrocarbons. Mcf. One thousand cubic feet. Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. MMBbls. One million barrels of crude oil or other liquid hydrocarbons. MMbtu. One million Btus. MMMbtu. One billion Btus. MMcf. One million cubic feet. MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. NYMEX. The New York Mercantile Exchange -23- Part II Item 6. Exhibits and Reports on Form 8-K (a) Exhibits: None (b) Reports on Form 8-K: On October 4, 2001, we filed a Current Report on Form 8-K to file the financial statements of Lariat Petroleum for the year ended December 31, 2000 and the pro forma combined financial statements of Lariat Petroleum and Newfield for the year ended December 31, 2000 and the six months in the period ended June 30, 2001 and to re-file our audited consolidated financial statements as of December 31, 2000 and 1999 and for each of the three years in the period ended December 31, 2000 for the sole purpose of adding a new Note 16. On October 9, 2001, we filed a current report on Form 8-K announcing the curtailment of a small portion of our fourth quarter 2001 natural gas production and the deferral of some capital projects. -24- SIGNATURE 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. NEWFIELD EXPLORATION COMPANY Date: November 2, 2001 By: /s/ TERRY W. RATHERT ----------------------------- Terry W. Rathert Vice President and Chief Financial Officer (Authorized Officer and Principal Financial Officer) -25- EXHIBIT INDEX EXHIBIT NUMBER DESCRIPTION ------- ----------- None -26-