10-Q 1 h10382e10vq.txt NEWFIELD EXPLORATION COMPANY - 9/30/2003 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (MARK ONE) [X] QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from ____________to____________. COMMISSION FILE NUMBER: 1-12534 NEWFIELD EXPLORATION COMPANY (Exact name of Registrant as specified in its charter) DELAWARE 72-1133047 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 363 NORTH SAM HOUSTON PARKWAY EAST SUITE 2020 HOUSTON, TEXAS 77060 (Address and Zip Code of principal executive offices) (281) 847-6000 (Registrant's telephone number, including area code) 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 twelve 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 [ ] Indicate by check mark whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ] As of November 6, 2003, there were 56,019,830 shares of the Registrant's Common Stock, par value $0.01 per share, outstanding. ================================================================================ TABLE OF CONTENTS
PART I Page ---- Item 1. Unaudited Financial Statements: Consolidated Balance Sheet as of September 30, 2003 and December 31, 2002.......................... 1 Consolidated Statement of Income for the three and nine months ended September 30, 2003 and 2002........................................................................ 2 Consolidated Statement of Cash Flows for the nine months ended September 30, 2003 and 2002........................................................................ 3 Consolidated Statement of Stockholders' Equity for the nine months ended September 30, 2003........................................................................... 4 Notes to Consolidated Financial Statements......................................................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................................................................. 19 Item 3. Quantitative and Qualitative Disclosures about Market Risk.............................................. 29 Item 4. Controls and Procedures................................................................................. 29 PART II Item 6. Exhibits and Reports on Form 8-K........................................................................ 30
ii NEWFIELD EXPLORATION COMPANY CONSOLIDATED BALANCE SHEET (IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED)
SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------- ------------ ASSETS Current assets: Cash and cash equivalents ...................................................... $ 24,970 $ 33,798 Accounts receivable--oil and gas ............................................... 145,966 125,670 Inventories .................................................................... 567 1,260 Derivative assets .............................................................. 35,430 2,655 Deferred taxes ................................................................. -- 13,023 Other current assets ........................................................... 39,019 30,788 Assets of discontinued operations .............................................. -- 31,633 ----------- ----------- Total current assets ....................................................... 245,952 238,827 ----------- ----------- Oil and gas properties (full cost method, of which $334,156 at September 30, 2003 and $261,558 at December 31, 2002 were excluded from amortization) ............. 3,895,380 3,299,022 Less--accumulated depreciation, depletion and amortization ......................... (1,562,088) (1,312,110) ----------- ----------- 2,333,292 1,986,912 ----------- ----------- Assets held for sale ............................................................... 35,000 35,000 Furniture, fixtures and equipment, net ............................................. 6,485 7,252 Derivative assets .................................................................. 7,401 4,439 Other assets ....................................................................... 16,725 19,452 Goodwill ........................................................................... 16,761 -- Assets of discontinued operations .................................................. -- 23,871 ----------- ----------- Total assets ............................................................... $ 2,661,616 $ 2,315,753 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable ............................................................... $ 17,271 $ 27,002 Accrued liabilities ............................................................ 200,090 198,084 Advances from joint owners ..................................................... 8,279 3,613 Current portion of secured notes payable ....................................... 531 11,215 Deferred taxes ................................................................. 2,626 -- Asset retirement obligation .................................................... 6,294 -- Derivative liabilities ......................................................... 24,198 49,610 Liabilities of discontinued operations ......................................... -- 6,283 ----------- ----------- Total current liabilities .................................................. 259,289 295,807 ----------- ----------- Other liabilities .................................................................. 13,323 15,949 Derivative liabilities ............................................................. 15,160 10,610 Long-term debt ..................................................................... 692,230 709,615 Asset retirement obligation ........................................................ 137,797 -- Liabilities of discontinued operations ............................................. -- 5,559 Deferred taxes ..................................................................... 197,293 124,777 ----------- ----------- Total long-term liabilities ................................................ 1,055,803 866,510 ----------- ----------- Company-obligated, mandatorily redeemable, convertible preferred securities of Newfield Financial Trust I ..................................................... -- 143,750 Minority interest .................................................................. -- 455 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; 56,876,630 and 52,603,662 shares issued and outstanding at September 30, 2003 and December 31, 2002, respectively) ................. 569 526 Additional paid-in capital ......................................................... 787,689 636,317 Treasury stock (at cost; 884,704 and 872,927 shares at September 30, 2003 and December 31, 2002, respectively) ............................................... (26,616) (26,213) Unearned compensation .............................................................. (11,857) (6,479) Accumulated other comprehensive income (loss): Foreign currency translation adjustment ........................................ 294 (3,888) Commodity derivatives .......................................................... 847 (27,295) Retained earnings .................................................................. 595,598 436,263 ----------- ----------- Total stockholders' equity ................................................. 1,346,524 1,009,231 ----------- ----------- Total liabilities and stockholders' equity ................................. $ 2,661,616 $ 2,315,753 =========== ===========
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, --------- --------- --------- --------- 2003 2002 2003 2002 --------- --------- --------- --------- Oil and gas revenues .......................................................... $ 248,664 $ 141,978 $ 772,107 $ 437,926 --------- --------- --------- --------- Operating expenses: Lease operating ........................................................... 31,083 20,309 85,807 63,298 Production and other taxes ................................................ 7,488 3,738 25,159 11,009 Transportation ............................................................ 1,624 1,730 5,046 4,377 Depreciation, depletion and amortization .................................. 100,897 69,910 293,407 215,937 General and administrative (includes stock compensation of $629 and $731 for the three months ended September 30, 2003 and 2002, respectively, and $2,115 and $2,066 for the nine months ended September 30, 2003 and 2002, respectively) .............................. 13,815 13,387 46,008 37,766 Gas sales obligation settlement and redemption of securities .............. -- -- 20,475 -- --------- --------- --------- --------- Total operating expenses ............................................. 154,907 109,074 475,902 332,387 --------- --------- --------- --------- Income from operations ........................................................ 93,757 32,904 296,205 105,539 Other income (expenses): Interest expense .......................................................... (13,357) (7,049) (45,025) (21,397) Capitalized interest ...................................................... 4,010 2,280 11,728 6,553 Dividends on convertible preferred securities of Newfield Financial Trust I .............................................. -- (2,336) (4,581) (7,008) Unrealized commodity derivative income (expense) .......................... 3,569 (13,952) 723 (25,477) Other ..................................................................... 444 137 956 4,004 --------- --------- --------- --------- (5,334) (20,920) (36,199) (43,325) --------- --------- --------- --------- Income from continuing operations before income taxes ......................... 88,423 11,984 260,006 62,214 Income tax provision (benefit): Current ................................................................... 760 15,195 36,341 33,443 Deferred .................................................................. 29,312 (10,851) 52,913 (11,178) --------- --------- --------- --------- 30,072 4,344 89,254 22,265 --------- --------- --------- --------- Income from continuing operations ............................................. 58,351 7,640 170,752 39,949 Income (loss) from discontinued operations, net of tax ........................ (8,972) 1,731 (16,992) 2,018 --------- --------- --------- --------- Income before cumulative effect of change in accounting principle ............. 49,379 9,371 153,760 41,967 Cumulative effect of change in accounting principle, net of tax: Adoption of SFAS No. 143 .................................................. -- -- 5,575 -- --------- --------- --------- --------- Net income ........................................................... $ 49,379 $ 9,371 $ 159,335 $ 41,967 ========= ========= ========= ========= Earnings per share: Basic -- Income from continuing operations ....................................... $ 1.04 $ 0.17 $ 3.17 $ 0.90 Income (loss) from discontinued operations .............................. (0.16) 0.04 (0.31) 0.05 Cumulative effect of change in accounting principle, net of tax ......... -- -- 0.10 -- --------- --------- --------- --------- Net income ........................................................... $ 0.88 $ 0.21 $ 2.96 $ 0.95 ========= ========= ========= ========= Diluted -- Income from continuing operations ....................................... $ 1.04 $ 0.17 $ 3.06 $ 0.89 Income (loss) from discontinued operations .............................. (0.16) 0.04 (0.30) 0.04 Cumulative effect of change in accounting principle, net of tax ......... -- -- 0.10 -- --------- --------- --------- --------- Net income ........................................................... $ 0.88 $ 0.21 $ 2.86 $ 0.93 ========= ========= ========= ========= Weighted average number of shares outstanding for basic earnings per share .... 55,887 44,420 53,785 44,337 ========= ========= ========= ========= Weighted average number of shares outstanding for diluted earnings per share .. 56,347 44,905 56,778 44,910 ========= ========= ========= =========
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, ---------------------------- 2003 2002 ----------- ----------- Cash flows from operating activities: Net income ................................................................. $ 159,335 $ 41,967 Adjustments to reconcile net income to net cash provided by continuing operating activities: (Income) loss from discontinued operations, net of tax .................. 16,992 (2,018) Depreciation, depletion and amortization ................................ 293,407 215,937 Gas sales obligation settlement and redemption of securities ............ 20,475 -- Stock compensation ...................................................... 2,115 2,066 Unrealized commodity derivative (income) expense ........................ (723) 25,477 Deferred taxes .......................................................... 52,913 (11,178) Cumulative effect of change in accounting principle ..................... (5,575) -- Changes in operating assets and liabilities: (Increase) decrease in accounts receivable -- oil and gas ............ (17,010) 3,551 Decrease in inventories .............................................. 698 158 (Increase) decrease in other current assets .......................... (14,229) 518 Decrease in other assets ............................................. 3,129 816 Decrease in accounts payable and accrued liabilities ................. (43,512) (2,717) Increase in advances from joint owners ............................... 4,666 164 Increase (decrease) in other liabilities ............................. (14,166) 2,117 ----------- ----------- Net cash provided by continuing activities ....................... 458,515 276,858 Net cash provided by discontinued activities ..................... 10,339 18,507 ----------- ----------- Net cash provided by operating activities .................... 468,854 295,365 ----------- ----------- Cash flows from investing activities: Purchase of business, net of cash acquired ................................. (91,742) -- Proceeds from sale of business ............................................. 9,678 -- Additions to oil and gas properties ........................................ (358,642) (217,576) Additions to furniture, fixtures and equipment ............................. (2,738) (2,027) ----------- ----------- Net cash used in continuing activities ........................... (443,444) (219,603) Net cash used in discontinued activities ......................... (3,085) (16,232) ----------- ----------- Net cash used in investing activities ........................ (446,529) (235,835) ----------- ----------- Cash flows from financing activities: Proceeds from borrowings under credit arrangements ......................... 1,285,500 490,000 Repayments of borrowings under credit arrangements ......................... (1,180,500) (558,000) Proceeds from issuance of common stock ..................................... 142,147 5,830 Purchases of treasury stock ................................................ (403) (366) Repurchases of secured notes ............................................... (63,068) -- Repayments of secured notes ................................................ (11,215) -- Deliveries under the gas sales obligation .................................. (8,442) -- Gas sales obligation settlement ............................................ (62,017) -- Redemption of trust preferred securities ................................... (148,449) -- ----------- ----------- Net cash used in continuing activities ........................... (46,447) (62,536) Net cash provided by (used in) discontinued activities ........... -- -- ----------- ----------- Net cash used in financing activities ........................ (46,447) (62,536) ----------- ----------- Effect of exchange rate changes on cash and cash equivalents ................... 194 90 ----------- ----------- Decrease in cash and cash equivalents .......................................... (23,928) (2,916) Cash and cash equivalents from continuing operations, beginning of period ...... 33,798 8,668 Cash and cash equivalents from discontinued operations, beginning of period .... 15,100 17,942 ----------- ----------- Cash and cash equivalents, end of period ....................................... $ 24,970 $ 23,694 =========== ===========
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)
COMMON STOCK TREASURY STOCK ADDITIONAL -------------------- -------------------- PAID-IN UNEARNED SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION ---------- ------ -------- -------- ---------- ------------ BALANCE, DECEMBER 31, 2002.... 52,603,662 $ 526 (872,927) $(26,213) $636,317 $ (6,479) Issuance of common stock...... 4,049,904 41 140,360 Issuance of restricted stock, less amortization of $522...................... 223,064 2 7,491 (6,971) Treasury stock, at cost....... (11,777) (403) Amortization of stock compensation................. 1,593 Tax benefit from exercise of stock options................ 3,521 Comprehensive income: Net income................. Foreign currency translation adjustment, net of tax of $(2,252)............... Reclassification adjustments for settled hedging positions, net of tax of $25,204.... Changes in fair value of outstanding hedging positions, net of tax of $(40,358).............. Total comprehensive income .................. ---------- ------ -------- -------- ---------- ----------- BALANCE, SEPTEMBER 30, 2003... 56,876,630 $ 569 (884,704) $(26,616) $787,689 $ (11,857) ========== ====== ======== ======== ======== =========== ACCUMULATED OTHER TOTAL RETAINED COMPREHENSIVE STOCKHOLDERS' EARNINGS INCOME (LOSS) EQUITY -------- ------------- ------------ BALANCE, DECEMBER 31, 2002.... $436,263 $(31,183) $1,009,231 Issuance of common stock...... 140,401 Issuance of restricted stock, less amortization of $522...................... 522 Treasury stock, at cost....... (403) Amortization of stock compensation................. 1,593 Tax benefit from exercise of stock options................ 3,521 Comprehensive income: Net income................. 159,335 159,335 Foreign currency translation adjustment, net of tax of $(2,252)............... 4,182 4,182 Reclassification adjustments for settled hedging positions, net of tax of $25,204.... (46,809) (46,809) Changes in fair value of outstanding hedging positions, net of tax of $(40,358).............. 74,951 74,951 ---------- Total comprehensive income .................. 191,659 -------- -------- ---------- BALANCE, SEPTEMBER 30, 2003 .. $595,598 $ 1,141 $1,346,524 ======== ======== ==========
The accompanying notes to consolidated financial statements are an integral part of this financial statement. 4 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: ORGANIZATION AND PRINCIPLES OF CONSOLIDATION We are an independent oil and gas company engaged in the exploration, development and acquisition of crude oil and natural gas properties. Our company was founded in 1989 and we acquired our first property in 1990. Our initial focus area was the Gulf of Mexico. In the mid-1990s, we began to expand our operations to other select areas. Our areas of operation now also include the U.S. onshore Gulf Coast, West Texas and the Anadarko and Arkoma Basins. Our financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to "Newfield," "we," "us" or "our" are to Newfield Exploration Company and its subsidiaries. These unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly our financial position as of, and results of operations for, the periods presented. These 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. These financial statements and notes should be read in conjunction with our consolidated financial statements and the notes thereto for the year ended December 31, 2002 included in our Annual Report on Form 10-K. On September 5, 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., which held all of our Australian assets. As a result of the sale, the historical results of operations of Newfield Exploration Australia Ltd. are reflected in our financial statements as "discontinued operations." Please see Note 2, "Discontinued Operations." Except where noted and for pro forma earnings per share, discussions in these notes relate to our continuing activities only. DEPENDENCE ON OIL AND GAS PRICES As an independent oil and gas producer, our revenue, profitability and future growth depend substantially on prevailing prices for oil and gas, 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 the price for oil or gas could have a material adverse effect on our financial position, results of operations, cash flows and our access to capital and on the quantities of reserves that may be economically produced. USE OF ESTIMATES The preparation of our financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Actual results could differ from these estimates. RECLASSIFICATIONS Certain reclassifications have been made to reported amounts for prior periods in order to conform with the current period presentation. These reclassifications, including those related to our discontinued operations (see Note 2, "Discontinued Operations"), did not impact our net income or stockholders' equity. STOCK-BASED COMPENSATION We account for our employee stock options using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25. 5 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) If the fair value based method of accounting under Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," had been applied, our net income and earnings per common share for the three and nine months ended September 30, 2003 and 2002 would have approximated the pro forma amounts below:
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------------- ---------------------------- 2003 2002 2003 2002 ---------- --------- ----------- ---------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net income: As reported .................................... $ 49,379 $ 9,371 $ 159,335 $ 41,967 Pro forma stock-based compensation expense (net of tax) ......................... (1,468) (1,449) (4,731) (4,052) ---------- --------- ----------- ---------- Pro forma ...................................... $ 47,911 $ 7,922 $ 154,604 $ 37,915 ========== ========= =========== ========== Earnings per share: Basic -- As reported .................................. $ 0.88 $ 0.21 $ 2.96 $ 0.95 Pro forma .................................... $ 0.86 $ 0.18 $ 2.88 $ 0.86 Diluted -- As reported .................................. $ 0.88 $ 0.21 $ 2.86 $ 0.93 Pro forma .................................... $ 0.85 $ 0.18 $ 2.78 $ 0.84
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," as of January 1, 2003. This statement changes the method of accounting for expected future costs associated with our obligation to perform site reclamation, dismantle facilities and plug and abandon wells. Prior to January 1, 2003, we recognized the undiscounted estimated cost to abandon our oil and gas properties over their estimated productive lives on a unit-of-production basis as a component of depreciation, depletion and amortization expense and no liability or capitalized costs associated with such abandonment were recorded on our consolidated balance sheet. SFAS No. 143 requires that, if a reasonable estimate of the fair value of an abandonment obligation can be made, a liability (an "asset retirement obligation" or "ARO") will be recorded on our consolidated balance sheet and the asset retirement cost will be capitalized in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs will be depreciated on a unit-of-production basis over the productive life of the related properties. Both the accretion and the depreciation are included in depreciation, depletion and amortization on our consolidated statement of income. At adoption of SFAS No. 143, a cumulative effect of change in accounting principle was required in order to recognize: - an initial ARO as a liability on our consolidated balance sheet; - an increase in oil and gas properties for the cost to abandon our oil and gas properties; - cumulative accretion of the ARO from the period incurred up to the January 1, 2003 adoption date; and - cumulative depreciation on the additional capitalized costs included in oil and gas properties up to the January 1, 2003 adoption date. The change in our ARO since adoption of SFAS No. 143 is set forth below (in thousands): Initial ARO as of January 1, 2003............................... $ 128,471 Accretion expense............................................... 5,500 Additions....................................................... 14,000 Settlement of ARO............................................... (3,880) ----------- Balance of ARO as of September 30, 2003......................... $ 144,091 ===========
6 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As a result of our adoption of SFAS No. 143, we recorded a $134.8 million increase in the net capitalized costs of our oil and gas properties. Additionally, we recognized an after-tax gain of $5.6 million (the after-tax amount by which additional capitalized costs, net of accumulated depreciation, exceeded the initial ARO, including in each case discontinued operations) for the cumulative effect of change in accounting principle. Had SFAS No. 143 been applied retroactively to the three and nine months ended September 30, 2002, our net income and earnings per share (without any cumulative effect of change in accounting principle) would have approximated the pro forma amounts below (in thousands, except per share amounts):
THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, 2002 SEPTEMBER 30, 2002 ------------------ ------------------ Net income: As reported...................... $ 9,371 $ 41,967 Pro forma........................ $ 8,854 $ 40,481 Earnings per share: Basic -- As reported...................... $ 0.21 $ 0.95 Pro forma........................ $ 0.20 $ 0.91 Diluted -- As reported...................... $ 0.21 $ 0.93 Pro forma........................ $ 0.20 $ 0.90
OTHER NEW ACCOUNTING STANDARDS In the second quarter of 2002, the FASB issued SFAS No. 145, "Recision of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections as of April 2002." This statement provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. Our adoption of SFAS No. 145 as of January 1, 2003 had no effect on our financial statements. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized when the liability is incurred and establishes that fair value is the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. Our adoption of SFAS No. 146 as of January 1, 2003 has had no effect on our financial statements. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS No. 133. The amendments set forth in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. Our adoption of SFAS No. 149 as of July 1, 2003 has had no effect on our financial statements. In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." This statement establishes standards for how an issuer classifies and measures on its balance sheet certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) because that financial instrument embodies an obligation of the issuer. SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003, and was otherwise effective for us as of July 1, 2003. Our adoption of the applicable provisions of this statement as of the indicated dates has had no effect on our financial statements. 7 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In November 2002, the FASB issued Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires certain guarantees to be recorded at fair value. FIN 45 had a dual effective date. The initial recognition and measurement provisions are applicable on a prospective basis only to guarantees issued or modified after December 31, 2002. The disclosure requirements in the interpretation were effective for us as of October 1, 2002. The adoption of the applicable provisions of FIN 45 at the indicated dates has not had a material effect on our financial statements. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51." The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights (these entities are referred to as "variable interest entities" or "VIEs") and how to determine if a business enterprise should consolidate the VIEs. This new model for consolidation applies to an entity for which either: - the equity investors (if any) do not have a controlling financial interest; or - the equity investment at risk is insufficient to finance the entity's activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that all enterprises with a significant variable interest in a VIE make additional disclosures regarding their relationship with the VIE. The provisions of this interpretation have had no effect on our financial statements. RECENT ACCOUNTING DEVELOPMENTS SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that certain intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new guidelines for accounting for goodwill and other intangible assets. Under the statement, goodwill and certain other intangible assets are reviewed annually for impairment but are not amortized. To our knowledge, substantially all publicly traded oil and gas companies have continued to include oil and gas rights and interests held under leases, governmental licenses or other contractual arrangements (leasehold interests) as part of oil and gas properties after SFAS No. 141 and SFAS No. 142 became effective. It is our understanding that the staffs of the FASB and the Securities and Exchange Commission may have questioned the oil and gas industry's application of SFAS Nos. 141 and 142 to leasehold interests. Based on our understanding of the SEC's and the FASB's potential interpretation of SFAS Nos. 141 and 142, if all leasehold interests were deemed to be intangible assets, for companies like us that use the full cost method of accounting for oil and gas activities: - leasehold interests with proved reserves that were acquired after June 30, 2001 and leasehold interests with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet; - our results of operations and cash flows would not be affected because leasehold costs would continue to be amortized in accordance with full cost accounting rules; and - the disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements. If SFAS Nos. 141 and 142 were applied as described above, at September 30, 2003 we had undeveloped leasehold interests of approximately $106 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as "intangible undeveloped leaseholds" and we had developed leasehold interests of approximately $620 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as "intangible developed leaseholds." We have had no contact with the staff of the FASB or the SEC regarding these matters. The foregoing discussion is based on information provided to us by other industry participants and by members of the accounting and legal profession. We will continue to classify our leasehold interests as tangible oil and gas properties until further guidance is provided. 8 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 2. DISCONTINUED OPERATIONS: On September 5, 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., which held all of our Australian assets. We received $9.7 million in proceeds, which was the agreed upon sales price plus estimated working capital at the time of closing. We recorded a receivable for an additional $9.6 million, which will be collected as the barrels in inventory at the time of sale are lifted and sold by the new owner. We recognized a loss of $9.9 million on the sale. The historical results of operations of Newfield Exploration Australia Ltd. are reflected in our financial statements as "discontinued operations." This reclassification affects not only the 2003 presentation of our financial statements, but also the presentation of all prior period financial statements. The results of operations of Newfield Exploration Australia Ltd., which have been classified as discontinued operations for the three and nine months ended September 30, 2003 and 2002, are summarized as follows (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ----------------------- ----------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Revenues ................................. $ 4,092 $ 10,632 $ 15,485 $ 24,334 Operating expenses ....................... (4,128) (9,426) (21,888) (19,332) -------- -------- -------- -------- Income (loss) from operations ............ (36) 1,206 (6,403) 5,002 Other income (expense) ................... 1,354 1,209 (3,478) (2,089) -------- -------- -------- -------- Income (loss) before income taxes ........ 1,318 2,415 (9,881) 2,913 Income tax benefit (provision) ........... (395) (684) 2,784 (895) -------- -------- -------- -------- Income (loss) from operations ............ 923 1,731 (7,097) 2,018 Loss on sale ............................. (9,895) -- (9,895) -- -------- -------- -------- -------- Income (loss) from discontinued operations $ (8,972) $ 1,731 $(16,992) $ 2,018 ======== ======== ======== ========
The major classes of assets and liabilities of Newfield Exploration Australia Ltd. that have been reclassified as discontinued operations as of December 31, 2002 are summarized as follows:
DECEMBER 31, 2002 ------------- (In thousands) Cash and cash equivalents .............................. $15,100 Accounts receivable--oil and gas ....................... 4,819 Inventories ............................................ 6,650 Other current assets ................................... 5,064 ------- Total current assets .............................. 31,633 ------- Oil and gas properties, net of accumulated depreciation, depletion and amortization ............ 23,093 Furniture, fixtures and equipment, net ................. 778 ------- Total other assets ................................ 23,871 ------- Total assets .................................. $55,504 ======= Accounts payable ....................................... $ 591 Accrued liabilities .................................... 5,692 ------- Total current liabilities ......................... 6,283 ------- Other liabilities ...................................... 1,027 Deferred taxes ......................................... 4,532 ------- Total other liabilities ........................... 5,559 ------- Total liabilities ............................. $11,842 =======
9 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 3. EARNINGS PER SHARE: Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted average number of shares of common stock outstanding during the period (the denominator). Diluted earnings per share incorporates the incremental shares issuable (if dilutive) upon the assumed exercise of stock options (using the treasury stock method) and upon the assumed conversion of our trust preferred securities, to the extent outstanding at any time during the period, as if exercise or conversion to common stock had occurred at the beginning of the period. If the assumed conversion of our trust preferred securities is dilutive, net income is increased for distributions accrued on the securities during the period. The following is a calculation of basic and diluted weighted average shares outstanding and EPS for the three and nine months ended September 30, 2003 and 2002:
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------------- ------------------------- 2003 2002 2003 2002 --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Income (numerator): Income from continuing operations ......................................... $ 58,351 $ 7,640 $ 170,752 $ 39,949 Income (loss) from discontinued operations, net of tax .................... (8,972) 1,731 (16,992) 2,018 --------- --------- --------- --------- Income before cumulative effect of change in accounting principle ......... 49,379 9,371 153,760 41,967 Cumulative effect of change in accounting principle, net of tax: Adoption of SFAS No. 143 .............................................. -- -- 5,575 -- --------- --------- --------- --------- Net income--basic ......................................................... 49,379 9,371 159,335 41,967 After-tax dividends on convertible trust preferred securities ............. -- -- 2,978 -- --------- --------- --------- --------- Net income--diluted ....................................................... $ 49,379 $ 9,371 $ 162,313 $ 41,967 ========= ========= ========= ========= Weighted average shares (denominator): Weighted average shares-- basic ....................................... 55,887 44,420 53,785 44,337 Dilutive effect of stock options outstanding at end of period .................................................... 460 485 443 573 Dilutive effect of convertible trust preferred securities ................................................ -- -- 2,550 -- --------- --------- --------- --------- Weighted average shares-- diluted ..................................... 56,347 44,905 56,778 44,910 ========= ========= ========= ========= Earnings per share: Basic -- Income from continuing operations ................................... $ 1.04 $ 0.17 $ 3.17 $ 0.90 Income (loss) from discontinued operations .......................... (0.16) 0.04 (0.31) 0.05 Cumulative effect of change in accounting principle, net of tax ..... -- -- 0.10 -- --------- --------- --------- --------- Net income ........................................................ $ 0.88 $ 0.21 $ 2.96 $ 0.95 ========= ========= ========= ========= Diluted -- Income from continuing operations ................................... $ 1.04 $ 0.17 $ 3.06 $ 0.89 Income (loss) from discontinued operations .......................... (0.16) 0.04 (0.30) 0.04 Cumulative effect of change in accounting principle, net of tax ..... -- -- 0.10 -- --------- --------- --------- --------- Net income ........................................................ $ 0.88 $ 0.21 $ 2.86 $ 0.93 ========= ========= ========= =========
The calculation of shares outstanding for diluted EPS above does not include the effect of outstanding stock options to purchase 601,650 and 1,519,900 shares for the three months ended September 30, 2003 and 2002, respectively, and 874,050 and 798,100 shares for the nine months ended September 30, 2003 and 2002, respectively, because to do so would have been antidilutive. On May 27, 2003, we completed the issuance and sale of 3.5 million shares of our common stock for net proceeds of approximately $131.2 million. We redeemed all of our trust preferred securities on June 27, 2003. Please see Note 8, "Convertible Preferred Securities of Newfield Financial Trust I." 10 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 4. ACQUISITIONS: EEX ACQUISITION On November 26, 2002, we acquired EEX Corporation primarily to expand our onshore operations. The EEX properties were complementary to our existing South Texas property base. The acquisition also accelerated our expansion into deepwater. The unaudited pro forma results presented below for the three and nine months ended September 30, 2002 have been prepared to illustrate the effects of the EEX acquisition on our results of operations under the purchase method of accounting as if we had acquired EEX on January 1, 2002. The pro forma results do not purport to represent what our actual results of operations would have been if the acquisition had in fact occurred on that date or to project our results of operations for any future date or period.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 2002 SEPTEMBER 30, 2002 ------------------ ------------------ (IN THOUSANDS, EXCEPT PER SHARE) Pro forma: Revenue......................................................... $ 176,689 $ 551,790 Income from operations.......................................... 32,038 112,842 Net income...................................................... 2,246 30,745 Basic earnings per share........................................ $ 0.04 $ 0.60 Diluted earnings per share...................................... $ 0.04 $ 0.59
PRIMARY NATURAL RESOURCES ACQUISITION On September 5, 2003, we acquired Primary Natural Resources, Inc. (PNR) for cash equal to approximately $91 million to strengthen our position in one of our focus areas -- the Anadarko and Arkoma Basins of the Mid-Continent. We accounted for the acquisition as a purchase using the accounting standards established in SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." Our consolidated financial statements include PNR's results of operations subsequent to September 5, 2003. We recorded the estimated fair values of the assets acquired and the liabilities assumed at September 5, 2003, which primarily included oil and gas properties of $94.4 million, a deferred tax liability of $19.7 million and goodwill of $16.8 million. We recorded the deferred tax liability to recognize the difference between the historical tax basis of PNR's assets and the acquisition costs recorded for book purposes. The recorded book value of the proved oil and gas properties was increased and goodwill was recorded to recognize this tax basis differential. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase. This goodwill is not deductible for tax purposes. 5. OIL AND GAS ASSETS: Oil and gas properties at the indicated dates consisted of the following:
SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------- ------------ (IN THOUSANDS) Subject to amortization ............................ $ 3,561,224 $ 3,037,464 Not subject to amortization Exploration wells in progress .................. 38,624 8,212 Development wells in progress .................. 14,609 6,732 Capitalized interest ........................... 20,890 14,036 Other capital costs: Incurred in 2003 ........................... 43,282 -- Incurred in 2002 ........................... 133,163 135,641 Incurred in 2001 ........................... 57,456 63,302 Incurred in 2000 and prior ................. 26,132 33,635 ----------- ----------- Total not subject to amortization ....... 334,156 261,558 ----------- ----------- Gross oil and gas properties ....................... 3,895,380 3,299,022 Accumulated depreciation, depletion and amortization (1,562,088) (1,312,110) ----------- ----------- Net oil and gas properties ......................... $ 2,333,292 $ 1,986,912 =========== ===========
11 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A portion of incurred (if not previously included in the amortization base) and future development costs associated with qualifying major development projects may be temporarily excluded from amortization. To qualify, a project must require significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore production platform from which development wells are to be drilled). Incurred and future costs are allocated between completed and future work. Any temporarily excluded costs are included in the amortization base upon the earlier of when the associated reserves are determined to be proved or impairment is indicated. As of September 30, 2003, we excluded from the amortization base $25.7 million associated with estimated development costs for our deepwater Gulf of Mexico project known as Glider (Green Canyon 247/248). The amounts included and excluded from the amortization base are based on the ratio of existing proved reserves to total proved reserves expected to be established upon completion of the Glider project. 6. GOODWILL: SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," have been applied to our Primary Natural Resources acquisition (see Note 4, "Acquisitions--Primary Natural Resources Acquisition"). Accordingly, PNR's tangible assets and liabilities have been adjusted to fair values with the remainder of the purchase price recorded as goodwill. We allocated all of the goodwill to our Mid-Continent reporting unit. This is the first time we have recorded goodwill in connection with an acquisition. Goodwill is not amortized but is reviewed for impairment at least annually or more frequently if impairment indicators arise. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of that reporting unit. If the fair value of the reporting unit is less than its book value (including goodwill) then goodwill is reduced to its implied fair value and the amount of the writedown is charged to earnings. We will perform our goodwill impairment test annually on December 31, or more frequently if impairment indicators arise. The fair value of the Mid-Continent reporting unit is based on our estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. Downward revisions of estimated reserves or production, increases in estimated future costs or depressed crude oil and natural gas prices could lead to an impairment of all or a portion of goodwill in future periods. 7. DEBT: As of the indicated dates, long-term debt consisted of the following:
SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------- ------------ (IN THOUSANDS) Senior unsecured debt: Bank revolving credit facility: Prime rate based loans .................................. $ -- $ -- LIBOR based loans ....................................... 139,000 28,000 -------- -------- Total bank revolving credit facility ................. 139,000 28,000 Money market lines of credit (1) ............................ 2,000 8,000 -------- -------- Total credit arrangements ............................ 141,000 36,000 -------- -------- 7.45% Senior Notes due 2007 ................................. 124,811 124,781 Fair value adjustment associated with interest rate hedges... 533 -- 7 5/8% Senior Notes due 2011 ................................ 174,902 174,895 Fair value adjustment associated with interest rate hedges... 543 -- -------- -------- Total senior unsecured notes ......................... 300,789 299,676 -------- -------- Total senior unsecured debt .......................... 441,789 335,676 -------- -------- 8 3/8% Senior Subordinated Notes due 2012 ....................... 248,077 247,971 Secured notes ................................................... 2,364 65,963 Gas sales obligation (1) ........................................ -- 60,005 -------- -------- Total long-term debt ................................. $692,230 $709,615 ======== ========
--------------- (1) Because capacity under our credit facility was available to repay borrowings under our money market lines of credit and to pay current amounts due under the gas sales obligation as of the indicated dates, these obligations are classified as long-term. At September 30, 2003 and December 31, 2002, the interest rate was 2.50% and 2.737%, respectively, for LIBOR-based loans under our credit facility and 3.0% and 2.615%, respectively, for the loans outstanding under our money market lines of credit. 12 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) INTEREST RATE SWAPS During September 2003, we entered into interest rate swap agreements to take advantage of low interest rates and to obtain what we view as a more desirable proportion of variable and fixed rate debt. These swap agreements provide for us to pay variable and receive fixed interest payments, and are designated as fair value hedges of a portion of our outstanding senior notes. At September 30, 2003, we hedged $50 million principal amount of our 7.45% Senior Notes due 2007 and $50 million principal amount of our 7 5/8% Senior Notes due 2011. SFAS No. 133 requires all derivatives to be recorded on the balance sheet at fair value. Changes in the fair value of derivatives designated as fair value hedges are recognized as offsets to the changes in fair value of the exposure being hedged. The fair value of these swaps are reflected within our derivative assets on our consolidated balance sheet. Changes in the fair value of the swaps are recorded as an adjustment to the carrying value of the associated long-term debt. Receipts and payments related to the interest rate swaps are reflected in interest expense. GAS SALES OBLIGATION SETTLEMENT Pursuant to a gas forward sales contract entered into in 1999, EEX committed to deliver approximately 50 Bcf of production to Bob West Treasure L.L.C. (BWT) in exchange for proceeds of $105 million. As of the date of our acquisition of EEX, we recorded a liability of approximately $62 million, which represented the then current market value of approximately 16 Bcf of reserves remaining under the gas sales contract. We accounted for the obligation under the gas sales contract as debt on our consolidated balance sheet. On March 31, 2003, pursuant to a settlement agreement with BWT and the other parties to related transactions, the gas sales contract, the swaps entered into by BWT in connection with the gas sales contract and all other agreements and security interests related to the gas sales contract were terminated in exchange for a payment by us of approximately $73 million. This payment represented: - the remaining unamortized obligation under the gas sales contract; - the fair market value of swaps entered into by BWT in conjunction with the gas sales contract; - various transaction fees related to the termination; and - an agreed upon value for BWT's membership interest in an EEX subsidiary. In connection with the settlement, we recognized a loss of $10.0 million under the caption "Gas sales obligation settlement and redemption of securities" on our consolidated statement of income. 8. CONVERTIBLE PREFERRED SECURITIES OF NEWFIELD FINANCIAL TRUST I: We redeemed all of the outstanding 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price of approximately $148.4 million or $38.31 on a per share of underlying common stock basis (excluding in each case accrued but unpaid distributions). The holders of only a small number of the securities elected to convert their securities into shares of our common stock prior to the redemption date (a total of 48,076 shares of common stock were issued). Included in the aggregate redemption price is $6.5 million of optional redemption premium. The premium and $4.0 million of unamortized offering costs (which were being amortized over the 30-year life of the securities) were recorded as an operating expense under the caption "Gas sales obligation settlement and redemption of securities" on our consolidated statement of income. We financed the redemption with the net proceeds from the issuance and sale of 3.5 million shares of our common stock on May 27, 2003 (approximately $131.2 million, or $37.49 per share) and borrowings under our revolving credit facility. 9. CONTINGENCIES: We have 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, we do not expect that these matters will have a material adverse effect on our financial position, cash flows or results of operations. 13 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 10. GEOGRAPHIC INFORMATION:
UNITED STATES INTERNATIONAL TOTAL ------------- ------------- ---------- (IN THOUSANDS) THREE MONTHS ENDED SEPTEMBER 30, 2003: Oil and gas revenues................................. $ 248,664 $ -- $ 248,664 Operating expenses: Lease operating.................................. 31,083 -- 31,083 Production and other taxes....................... 7,488 -- 7,488 Transportation................................... 1,624 -- 1,624 Depreciation, depletion and amortization......... 100,897 -- 100,897 Allocated income taxes........................... 37,650 -- ---------- ---------- Net income from oil and gas properties....... $ 69,922 $ -- ========== ========== General and administrative (inclusive of stock compensation) (1).............................. 13,815 ---------- Total operating expenses..................... 154,907 --------- Income from operations............................... 93,757 Interest expense and dividends, net of interest income, capitalized interest and other ........ (8,903) Unrealized commodity derivative income........... 3,569 ---------- Income before income taxes........................... $ 88,423 ========== Total long-lived assets.............................. $2,287,991 $ 45,301 $2,333,292 ========== ========== ========== Additions to long-lived assets....................... $ 253,185 $ 6,393 $ 259,578 ========== ========== ========== THREE MONTHS ENDED SEPTEMBER 30, 2002: Oil and gas revenues................................. $ 141,978 $ -- $ 141,978 Operating expenses: Lease operating.................................. 20,309 -- 20,309 Production and other taxes....................... 3,738 -- 3,738 Transportation................................... 1,730 -- 1,730 Depreciation, depletion and amortization......... 69,910 -- 69,910 Allocated income taxes........................... 16,202 -- ---------- ---------- Net income from oil and gas properties....... $ 30,089 $ -- ========== ========== General and administrative (inclusive of stock compensation) (1).............................. 13,387 ---------- Total operating expenses..................... 109,074 ---------- Income from operations............................... 32,904 Interest expense and dividends, net of interest income, capitalized interest and other......... (6,968) Unrealized commodity derivative expense.......... (13,952) --------- Income before income taxes........................... $ 11,984 ========== Total long-lived assets.............................. $1,370,707 $ 35,186 $1,405,893 ========== ========== ========== Additions to long-lived assets....................... $ 151,657 $ 4,875 $ 156,532 ========== ========== ==========
-------------- (1) General and administrative expense includes stock compensation charges of $629 and $731 for the three months ended September 30, 2003 and 2002, respectively. 14 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
UNITED STATES INTERNATIONAL TOTAL ------------- ------------- ---------- (IN THOUSANDS) NINE MONTHS ENDED SEPTEMBER 30, 2003: Oil and gas revenues................................. $ 772,107 $ -- $ 772,107 Operating expenses: Lease operating.................................. 85,807 -- 85,807 Production and other taxes....................... 25,159 -- 25,159 Transportation................................... 5,046 -- 5,046 Depreciation, depletion and amortization......... 293,407 -- 293,407 Allocated income taxes........................... 126,941 -- ---------- ---------- Net income from oil and gas properties....... $ 235,747 $ -- ========== ========== Gas sales obligation settlement and redemption of securities.................................. 20,475 General and administrative (inclusive of stock compensation) (1).............................. 46,008 ---------- Total operating expenses..................... 475,902 ---------- Income from operations............................... 296,205 Interest expense and dividends, net of interest income, capitalized interest and other ........ (36,922) Unrealized commodity derivative income........... 723 ---------- Income before income taxes........................... $ 260,006 ========== Total long-lived assets.............................. $2,287,991 $ 45,301 $2,333,292 ========== ========== ========== Additions to long-lived assets (2) .................. $ 587,400 $ 8,958 $ 596,358 ========== ========== ========== NINE MONTHS ENDED SEPTEMBER 30, 2002: Oil and gas revenues................................. $ 437,926 $ -- $ 437,926 Operating expenses: Lease operating.................................. 63,298 -- 63,298 Production and other taxes....................... 11,009 -- 11,009 Transportation................................... 4,377 -- 4,377 Depreciation, depletion and amortization......... 215,937 -- 215,937 Allocated income taxes........................... 50,157 -- ---------- ---------- Net income from oil and gas properties....... $ 93,148 $ -- ========== ========== General and administrative (inclusive of stock compensation) (1).............................. 37,766 ---------- Total operating expenses..................... 332,387 ---------- Income from operations............................... 105,539 Interest expense and dividends, net of interest income, capitalized interest and other......... (17,848) Unrealized commodity derivative expense.......... (25,477) ---------- Income before income taxes........................... $ 62,214 ========== Total long-lived assets.............................. $1,370,707 $ 35,186 $1,405,893 ========== ========== ========== Additions to long-lived assets....................... $ 221,991 $ 6,998 $ 228,989 ========== ========== ==========
-------------- (1) General and administrative expense includes stock compensation charges of $2,115 and $2,066 for the nine months ended September 30, 2003 and 2002, respectively. (2) Includes domestic additions of $115.1 million for capitalized asset retirement obligations. 15 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 11. COMMODITY DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES: We utilize swap, floor, collar and three-way collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our oil and gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract. For a floor contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are not required to make any payment in connection with the settlement of a floor contract. For a collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract, we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract and neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price for such contract. A three-way collar contract consists of a standard collar contract plus an additional put sold by us at a price below the floor price of the collar. The additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put price. Combining the collar contract with the additional put results in us being entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put price if the settlement price is equal to or less than the additional put price. If the settlement price is greater than the additional put price, the result is the same as it would have been with a standard collar contract only. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional cashless collar while defraying the associated cost with the sale of the additional put. Substantially all of our oil and gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, volatility and, in the case of collars and floors, the time value of options. The calculation of the fair value of collars and floors requires the use of the Black-Scholes option-pricing model. On the date we enter into a derivative contract, we designate the derivative as a hedge of the variability in cash flows associated with the forecasted sale of our oil and gas production. After-tax changes in the fair value of a derivative that is highly effective and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded under the caption "Accumulated other comprehensive income (loss)--Commodity derivatives" on our consolidated balance sheet until the sale of the hedged oil and gas production. Upon the sale of the hedged production, the net after-tax change in the fair value of the associated derivative recorded under the caption "Accumulated other comprehensive income (loss)--Commodity derivatives" is reversed and the gain or loss on the hedge, to the extent that it is effective, is reported in "Oil and gas revenues" on our consolidated statement of income. At September 30, 2003, we had a net $0.8 million in after-tax income recorded under the caption "Accumulated other comprehensive income (loss)--Commodity derivatives" associated with commodity derivatives. We expect hedged production associated with commodity derivatives that account for a net gain of approximately $2.1 million to be sold within the next 12 months and hedged production associated with the remaining net loss of approximately $1.3 million to be sold subsequent to that period. The actual gain or loss on these commodity derivatives could vary significantly as a result of changes in market conditions and other factors. Any hedge ineffectiveness (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period under the caption "Unrealized commodity derivative income (expense)" on our consolidated statement of income. Prior to January 1, 2002, the periodic changes in the time value component of our collar and floor contracts were treated as ineffective and were reported under the caption "Unrealized commodity derivative income (expense)" on our consolidated statement of income for the period in which the change occurred. On January 1, 2002, we began assessing hedge effectiveness based on the total changes in cash flows on our collar and floor contracts without adjustment for time value as described by DIG Issue G20, "Cash Flow Hedges: Assessing and Measuring the Effectiveness of a Purchased Option Used in a Cash Flow Hedge." Pursuant to the guidance in DIG Issue G20, we elected to prospectively record subsequent changes in fair value associated with time value under the caption "Accumulated other comprehensive income (loss)--Commodity derivatives" on our consolidated balance sheet. As a result, amounts recorded in the third quarter and first nine months of 2002 primarily reflect the reversal of the time value gains that were recognized in 2001 and a diminutive amount representing the ineffective portion of our hedges. 16 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) We formally document all relationships between derivative instruments and hedged production, as well as our risk management objective and strategy for particular derivative contracts. 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. We also formally assess (both at the derivative's inception and on an ongoing basis) whether the derivatives being utilized have been highly effective in offsetting changes in the cash flows of hedged production and whether those derivatives may be expected to remain highly effective in future periods. If it is determined that a derivative has ceased to be highly effective as a hedge, we will discontinue hedge accounting prospectively. If hedge accounting is discontinued and the derivative remains outstanding, we will carry the derivative at its fair value on our consolidated balance sheet and recognize all subsequent changes in the fair value of the derivative on our consolidated statement of income for the period in which the change occurred. Hedge accounting was not discontinued during the periods presented for any hedging instruments. Although our three-way collar contracts are effective as economic hedges of our commodity price exposure, they do not qualify for hedge accounting under SFAS No. 133. These contracts are carried at their fair value on our consolidated balance sheet under the captions "Derivative assets" and "Derivative liabilities." We recognize all changes in the fair value of our three-way collar contracts on our consolidated statement of income for the period in which the change occurs under the caption "Unrealized commodity derivative income (expense)." NATURAL GAS As of September 30, 2003, we had entered into derivative contracts that qualify as cash flow hedges with respect to our future natural gas production as follows:
NYMEX CONTRACT PRICE PER MMBTU ------------------------------------------------------------------- COLLARS ------------------------------------------------------- FLOORS CEILINGS SWAPS -------------------------- ------------------------- VOLUME IN (WEIGHTED WEIGHTED WEIGHTED PERIOD AND TYPE OF CONTRACT MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE --------------------------------- ---------- -------- ------------- --------- -------------- -------- October 2003 - December 2003 Price swap contracts.......... 15,617 $4.43 -- -- -- -- Collar contracts ............. 20,597 -- $3.50 - $5.50 $4.80 $3.90 - $15.00 $7.38 Floor contracts............... 3,000 -- -- -- -- -- January 2004 - March 2004 Price swap contracts.......... 9,835 5.39 -- -- -- -- Collar contracts ............. 20,755 -- 3.00 - 5.50 4.94 4.16 - 15.00 8.52 April 2004 - June 2004 Price swap contracts.......... 10,365 4.77 -- -- -- -- Collar contracts ............. 4,845 -- 3.00 - 4.50 4.27 4.16 - 5.75 5.31 July 2004 - September 2004 Price swap contracts.......... 10,075 4.75 -- -- -- -- Collar contracts.............. 4,845 -- 3.00 - 4.50 4.27 4.16 - 5.75 5.31 October 2004 - December 2004 Price swap contracts.......... 5,245 4.79 -- -- -- -- Collar contracts.............. 1,945 -- 3.00 - 4.50 4.11 4.16 - 5.75 5.20 January 2005 - December 2005 Price swap contracts.......... 5,440 4.43 -- -- -- -- Collar contracts ............. 1,380 -- 3.50 3.50 4.16 4.16 NYMEX CONTRACT PRICE PER MMBTU ------------------------------- FLOOR CONTRACTS ESTIMATED ----------------------------- FAIR VALUE WEIGHTED ASSET (LIABILITY) PERIOD AND TYPE OF CONTRACT RANGE AVERAGE (IN MILLIONS) --------------------------------- ------------- -------- ----------------- October 2003 - December 2003 Price swap contracts.......... -- -- $ (6.0) Collar contracts ............. -- -- 4.3 Floor contracts............... $4.70 - $4.98 $4.78 2.0 January 2004 - March 2004 Price swap contracts.......... -- -- 1.9 Collar contracts.............. -- -- 6.4 April 2004 - June 2004 Price swap contracts.......... -- -- 0.3 Collar contracts.............. -- -- (0.2) July 2004 - September 2004 Price swap contracts.......... -- -- 0.3 Collar contracts.............. -- -- (0.3) October 2004 - December 2004 Price swap contracts.......... -- -- -- Collar contracts ............. -- -- (0.5) January 2005 - December 2005 Price swap contracts.......... -- -- (1.6) Collar contracts ............. -- -- (1.1) ------ $ 5.5 ======
17 NEWFIELD EXPLORATION COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) As of September 30, 2003, we also had entered into three-way collar contracts with respect to our future natural gas production as set forth in the table below. These contracts do not qualify for hedge accounting.
NYMEX CONTRACT PRICE PER MMBTU ------------------------------------------------------------------ COLLARS --------------------------------------- ADDITIONAL PUT FLOORS CEILINGS ESTIMATED ------------------------ ---------------------- -------------- FAIR VALUE VOLUME IN WEIGHTED WEIGHTED WEIGHTED ASSET (LIABILITY) PERIOD AND TYPE OF CONTRACT MMMBTUS RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE (IN MILLIONS) ----------------------------- -------- -------------- -------- ------------- ------- ----- -------- ----------------- April 2004 - June 2004 3-Way collar contracts ... 4,500 $3.61 - $3.76 $3.67 $4.61 - $4.76 $4.67 $5.20 $5.20 $ -- July 2004 - September 2004 3-Way collar contracts ... 4,500 3.61 - 3.76 3.67 4.61 - 4.76 4.67 5.20 5.20 (0.2) October 2004 - December 2004 3-Way collar contracts ... 1,500 3.61 - 3.76 3.67 4.61 - 4.76 4.67 5.20 5.20 (0.2) ------ $ (0.4) ======
OIL As of September 30, 2003, we had entered into derivative contracts that qualify as cash flow hedges with respect to our future oil production as follows:
NYMEX CONTRACT PRICE PER BBL -------------------------------------------------------------------- COLLARS ------------------------------------------------------- FLOORS CEILINGS ESTIMATED SWAPS -------------------------- ------------------------- FAIR VALUE VOLUME IN (WEIGHTED WEIGHTED WEIGHTED ASSET (LIABILITY) PERIOD AND TYPE OF CONTRACT BBLS AVERAGE) RANGE AVERAGE RANGE AVERAGE (IN MILLIONS) ------------------------------- ---------- -------- --------------- --------- -------------- -------- ----------------- October 2003 - December 2003 Price swap contracts........ 300,000 $27.55 -- -- -- -- $ (0.4) Collar contracts............ 627,000 -- $22.00 - $24.00 $22.47 $26.35 - $29.70 $27.83 (1.0) January 2004 - March 2004 Price swap contracts........ 69,000 26.86 -- -- -- -- -- Collar contracts............ 405,000 -- 22.00 - 24.00 22.70 26.04 - 29.70 27.28 (0.6) April 2004 - June 2004 Price swap contracts........ 24,000 23.23 -- -- -- -- (0.1) Collar contracts............ 300,000 -- 22.00 - 24.00 22.80 26.04 - 28.85 27.16 (0.3) July 2004 - September 2004 Price swap contracts........ 24,000 23.23 -- -- -- -- (0.1) Collar contracts............ 60,000 -- 22.00 22.00 26.35 26.35 (0.1) October 2004 - December 2004 Price swap contracts........ 24,000 23.23 -- -- -- -- (0.1) January 2005 - December 2005 Price swap contracts........ 204,000 22.63 -- -- -- -- (0.5) ------ $ (3.2) ======
As of September 30, 2003, we also had entered into three-way collar contracts with respect to our future oil production as set forth in the table below. These contracts do not qualify for hedge accounting.
NYMEX CONTRACT PRICE PER BBL ------------------------------------------------------------------- COLLARS ------------------------------------------------------ FLOORS CEILINGS ESTIMATED ------------------------ -------------------------- FAIR VALUE VOLUME IN ADDITIONAL WEIGHTED WEIGHTED ASSET (LIABILITY) PERIOD AND TYPE OF CONTRACT BBLS PUT RANGE AVERAGE RANGE AVERAGE (IN MILLIONS) ------------------------------- ---------- ---------- ------------- -------- --------------- -------- ----------------- January 2004 - March 2004 3-Way collar contracts...... 286,000 $21.00 $26.00 $26.00 $29.80 - $30.05 $29.98 $ 0.1 April 2004 - June 2004 3-Way collar contracts...... 377,000 21.00 25.00 - 26.00 25.76 29.70 - 30.05 29.91 0.2 July 2004 - September 2004 3-Way collar contracts...... 379,000 21.00 25.00 - 26.00 25.76 29.70 - 30.05 29.91 0.1 October 2004 - December 2004 3-Way collar contracts...... 379,000 21.00 25.00 - 26.00 25.76 29.70 - 30.05 29.91 0.1 January 2005 - December 2005 3-Way collar contracts...... 90,000 21.00 25.00 25.00 29.70 29.70 -- ------- $ 0.5 =======
18 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL We are an independent oil and gas company engaged in the exploration, development and acquisition of crude oil and natural gas properties. Our company was founded in 1989 and we acquired our first property in 1990. Our initial focus area was the Gulf of Mexico. In the mid-1990s, we began to expand our operations to other select areas. Our areas of operation now also include the U.S. onshore Gulf Coast, West Texas and the Anadarko and Arkoma Basins. Unless otherwise specified or the context otherwise requires, all references in these notes to "Newfield," "we," "us" or "our" are to Newfield Exploration Company and its subsidiaries. If you are not familiar with any of the oil and gas terms used in this report, please refer to the explanation of such terms under the caption "Commonly Used Oil and Gas Terms" at the end of this item. On September 5, 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., which held all of our Australian assets. As a result of the sale, the historical results of operations of Newfield Exploration Australia Ltd. are reflected in our financial statements as "discontinued operations." Please see Note 2, "Discontinued Operations," to our consolidated financial statements appearing earlier in this report. Except where noted, discussions in this report relate to our continuing activities. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and our ability to find, develop and acquire oil and gas reserves that are economically recoverable. A substantial or extended decline in the prices for oil or gas could have a material adverse effect on us. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Actual results could differ from these estimates and assumptions. We use the full cost method of accounting for our oil and gas activities. OIL AND GAS PRICES. Prices for oil and gas fluctuate widely. Oil and gas prices affect: - the amount of cash flow available for capital expenditures; - our ability to borrow and raise additional capital; - the amount of oil and gas that we can economically produce; and - the accounting for our oil and gas activities. We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production to, among other things, reduce our exposure to commodity price fluctuations. RESERVE REPLACEMENT. As is generally the case, our producing properties in the Gulf of Mexico and the onshore Gulf Coast often have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and gas reserves. SIGNIFICANT ESTIMATES. We believe the most difficult, subjective or complex judgments and estimates we must make in connection with the preparation of our financial statements are: - remaining proved oil and gas reserves; - future costs to develop and abandon our oil and gas properties; - timing of our future drilling, development and abandonment activities; - allocating the purchase price associated with business combinations; and - the valuation of our derivative positions. Please see "Critical Accounting Policies and Estimates" and "Other Factors Affecting Our Business and Financial Results" in Item 7 of our annual report for the year ended December 31, 2002 for a more detailed discussion of the foregoing matters and a discussion of a number of other factors that affect our business, financial condition and results of operations. This report should be read together with these discussions. 19 RESULTS OF CONTINUING OPERATIONS EARNINGS PER SHARE. We redeemed all of the outstanding preferred securities of Newfield Financial Trust I on June 27, 2003. We primarily financed the redemption with the net proceeds from the issuance and sale of 3.5 million shares of our common stock on May 27, 2003. For a further description of these transactions, please see "--Redemption of Trust Preferred Securities." Our diluted earnings per share for the nine months ended September 30, 2003 were negatively impacted by the continuing dilutive effect of the convertible trust preferred securities following the issuance of the 3.5 million shares of our common stock. REVENUES. All of our revenues are derived from the sale of our oil and gas production and the settlement of hedging contracts associated with our production. Our revenues may vary significantly from period to period as a result of changes in commodity prices. Revenues for the third quarter and the first nine months of 2003 were about 75% higher than the comparable periods of 2002 because of higher commodity prices and higher production.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE ---------------------- INCREASE ---------------------- INCREASE 2003 2002 (DECREASE) 2003 2002 (DECREASE) -------- -------- ---------- -------- -------- ---------- PRODUCTION: Natural gas (Bcf)................... 47.4 34.8 36% 138.1 106.5 30% Oil and condensate (MMBbls)......... 1.5 1.2 25% 4.6 3.9 18% Total (Bcfe)........................ 56.1 41.9 34% 165.5 129.7 28% AVERAGE REALIZED PRICES(1): Natural gas (per Mcf)............... $ 4.40 $ 3.19 38% $ 4.64 $ 3.22 44% Oil and condensate (per Bbl)........ 26.52 24.84 7% 27.71 23.52 18%
----------------- (1) For purposes of this table, average realized prices for natural gas and oil and condensate are presented net of all applicable transportation expenses, which reduced the average realized price of natural gas by $0.03 and $0.04 for the three months ended September 30, 2003 and 2002, respectively, and by $0.02 and $0.03 for the nine months ended September 30, 2003 and 2002, respectively. The average realized price of oil and condensate was reduced by $0.32 and $0.46 for the three months ended September 30, 2003 and 2002, respectively, and by $0.36 for both the nine month periods ended September 30, 2003 and 2002. Average realized prices include the effects of hedging. PRODUCTION. Our total oil and gas production (stated on a natural gas equivalent basis) increased in the third quarter and the first nine months of 2003 when compared to the same periods in 2002 primarily because of our acquisition of EEX, other small acquisitions and successful drilling efforts. NATURAL GAS. Our third quarter and first nine months of 2003 natural gas production increased primarily because of our acquisition of EEX and successful drilling in the Gulf of Mexico in late 2002. CRUDE OIL AND CONDENSATE. Our oil production for the third quarter and the first nine months of 2003, as compared to the same periods of the prior year, increased primarily because of our acquisition of EEX and other small acquisitions. EFFECTS OF HEDGING ON REALIZED PRICES. The following table presents information about the effects of our hedging program 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, 2003............. $ 4.40 $ 4.78 92% Three months ended September 30, 2002............. 3.19 3.02 106% Nine months ended September 30, 2003.............. 4.64 5.42 86% Nine months ended September 30, 2002.............. 3.22 2.86 113% Crude Oil and Condensate: Three months ended September 30, 2003............. $ 26.52 $ 28.68 92% Three months ended September 30, 2002............. 24.84 26.10 95% Nine months ended September 30, 2003.............. 27.71 29.81 93% Nine months ended September 30, 2002.............. 23.52 23.49 100%
------------------- (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. 20 OPERATING EXPENSES. We are a growth oriented company. As such, our proved reserves and production have grown steadily since our founding. Naturally, our operating expenses have increased with our growth. As a result, we believe the most informative way to analyze changes in our operating expenses from one period to another is on a unit-of-production, or Mcfe, basis. The following table presents information about our operating expenses for the third quarter of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT (PER MCFE) (IN THOUSANDS) ------------------------------------ ------------------------------------ THREE MONTHS ENDED THREE MONTHS ENDED SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE -------------------- INCREASE ---------- ------------ INCREASE 2003 2002 (DECREASE) 2003 2002 (DECREASE) ------ ------ ---------- -------- -------- --------- Lease operating......................... $ 0.55 $ 0.48 15% $ 31,083 $ 20,309 53% Production and other taxes.............. 0.13 0.09 44% 7,488 3,738 100% Transportation.......................... 0.03 0.04 (25%) 1,624 1,730 (6%) Depreciation, depletion and amortization.......................... 1.80 1.67 8% 100,897 69,910 44% General and administrative (exclusive of stock compensation) (1)............ 0.23 0.30 (23%) 13,186 12,656 4% Total............................. 2.74 2.58 6% 154,278 108,343 42%
-------------------------- (1) Stock compensation charges were $629, or $0.01 per Mcfe, and $731, or $0.02 per Mcfe, for the three months ended September 30, 2003 and 2002, respectively. Our total operating expense (excluding stock compensation) for the third quarter of 2003, stated on a unit-of-production basis, increased 6% over the same period in 2002. The increase was primarily related to the following items: - Lease operating expense (LOE) on a unit-of-production basis for the third quarter of 2003 increased over the same period of last year in large part due to a higher level of workover activity in 2003 and the addition of higher cost properties through the EEX acquisition. - Production taxes on a unit-of-production basis increased in the third quarter of 2003 due to higher commodity prices when compared to the same period of last year. Additionally, a greater percentage of our production is now onshore and subject to production taxes. - Depreciation, depletion and amortization (DD&A) (excluding furniture, fixtures and equipment) for the third quarter of 2003 was $1.74 per Mcfe versus $1.65 for the comparable period of 2002. Our adoption of SFAS No. 143 (see "--Adoption of SFAS No. 143" below) resulted in $0.03 per Mcfe of the increase. The remainder of the increase resulted from the increased cost of reserve additions since the third quarter of 2002. - General and administrative expense (G&A) before incentive compensation expense and capitalized direct internal costs on a unit-of-production basis decreased by $0.04 per Mcfe for the third quarter of 2003, as compared to the same period of 2002, because production growth was greater than the growth in our workforce. This decrease was offset by a significant increase in incentive compensation expense during the third quarter of 2003, as compared to the same period of 2002, because of the significant increase in our earnings. During the third quarter of 2003, we capitalized $6.2 million of direct internal costs compared to $2.3 million in the same period of 2002. The following table presents information about our operating expenses for the first nine months of 2003 and 2002.
UNIT-OF-PRODUCTION AMOUNT (PER MCFE) (IN THOUSANDS) ------------------------------------ ------------------------------------ NINE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, PERCENTAGE SEPTEMBER 30, PERCENTAGE -------------------- INCREASE ---------- ------------ INCREASE 2003 2002 (DECREASE) 2003 2002 (DECREASE) ------ ------ ---------- -------- -------- --------- Lease operating......................... $ 0.52 $ 0.49 6% $ 85,807 $ 63,298 36% Production and other taxes.............. 0.15 0.08 88% 25,159 11,009 129% Transportation.......................... 0.03 0.03 -- 5,046 4,377 15% Depreciation, depletion and amortization.......................... 1.77 1.66 7% 293,407 215,937 36% General and administrative (exclusive of stock compensation) (1)............ 0.27 0.28 (4%) 43,893 35,700 23% Total............................. 2.74 2.54 8% 453,312 330,321 37%
------------------ (1) Stock compensation charges were $2,115, or $0.01 per Mcfe, and $2,066, or $0.02 per Mcfe, for the nine months ended September 30, 2003 and 2002, respectively. Total operating expense, inclusive of these charges but excluding the gas sales obligation settlement and redemption of our trust preferred securities, was $455,427, or $2.76 per Mcfe, and $332,387, or $2.56 per Mcfe, for the nine months ended September 30, 2003 and 2002, respectively. 21 Our total operating expense (excluding stock compensation, the gas sales obligation settlement and redemption of our trust preferred securities) for the first nine months of 2003, stated on a unit-of-production basis, increased 8% over the same period in 2002. The increase was primarily related to the following items: - Lease operating expense (LOE) on a unit-of-production basis for the first nine months of 2003 increased over the same period of last year in large part due to a higher level of workover activity in 2003 and the addition of higher cost properties through the EEX acquisition. - Production taxes on a unit-of-production basis increased in the first nine months of 2003 due to higher commodity prices when compared to the same period of last year. Additionally, a greater percentage of our production is now onshore and subject to production taxes. - DD&A (excluding furniture, fixtures and equipment) for the first nine months of 2003 was $1.72 per Mcfe versus $1.65 for the comparable period of 2002. Our adoption of SFAS No. 143 (see "--Adoption of SFAS No. 143" below) resulted in $0.03 per Mcfe of the increase. The remainder of the increase resulted from the increased cost of reserve additions since the third quarter of 2002. - G&A before capitalized direct internal costs on a unit-of- production basis for the first nine months of 2003 increased by $0.06 per Mcfe as a result of a significant increase in incentive compensation expense during the 2003 period as compared to the 2002 period. This increase is the result of the significant increase in our earnings. During the first nine months of 2003, we capitalized $20.4 million of direct internal costs, compared to $6.4 million in the same period of 2002. GAS SALES OBLIGATION SETTLEMENT. Pursuant to a gas forward sales contract entered into in 1999, EEX committed to deliver approximately 50 Bcf of production to Bob West Treasure L.L.C. (BWT) in exchange for proceeds of $105 million. As of the date of our acquisition of EEX, we recorded a liability of approximately $62 million, which represented the then current market value of approximately 16 Bcf of reserves remaining under the gas sales contract. We accounted for the obligation under the gas sales contract as debt on our consolidated balance sheet. On March 31, 2003, pursuant to a settlement agreement with BWT and the other parties to related transactions, the gas sales contract, the swaps entered into by BWT in connection with the gas sales contract and all other agreements related to the gas sales contract, including the guarantee and all liens and other security interests on EEX's properties, were terminated in exchange for a payment by us of approximately $73 million. This payment represented: - the remaining unamortized obligation under the gas sales contract; - the fair market value of swaps entered into by BWT in conjunction with the gas sales contract; - various transactions fees related to the termination; and - an agreed upon value for BWT's membership interest in an EEX subsidiary. In connection with the settlement, we recognized a loss of $10 million under the caption "Gas sales obligation settlement and redemption of securities" on our consolidated statement of income. About $9 million of the loss was related to the change in the fair market value of the committed production and the swaps between the date we acquired EEX and the settlement date. As a result of the termination of the gas sales contract, the remaining committed volumes of approximately 6.0 Bcf for 2003 and 6.7 Bcf for 2004 became available to be sold on the open market at current market prices. Simultaneously with the termination of the gas sales contract, we hedged the May 2003 through October 2003 volumes at a volume-weighted average price of $5.21 per MMBtu. Proceeds from the sale of these previously committed volumes are recognized in revenues. REDEMPTION OF TRUST PREFERRED SECURITIES. We redeemed all of the outstanding 6 1/2% Cumulative Quarterly Income Convertible Preferred Securities of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price of approximately $148.4 million or $38.31 on a per share of underlying common stock basis (excluding in each case accrued but unpaid distributions). The holders of only a small number of the securities elected to convert their securities into shares of our common stock prior to the redemption date (a total of 48,076 shares of common stock were issued). Included in the aggregate redemption price is $6.5 million of optional redemption premium. The premium and $4.0 million of unamortized offering costs (which were being amortized over the 30-year life of the securities) were recorded as an operating expense under the caption "Gas sales obligation settlement and redemption of securities" on our consolidated statement of income. We financed the redemption with the net proceeds from the issuance and sale of 3.5 million shares of our common stock on May 27, 2003 (approximately $131.2 million, or $37.49 per share) and borrowings under our revolving credit facility. 22 INTEREST EXPENSE. Interest expense for the third quarter and the first nine months of 2003 increased compared to the same periods last year primarily because of debt incurred in connection with the EEX acquisition in late 2002.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------- --------------------- 2003 2002 2003 2002 ------- ------ ------- ------- (IN MILLIONS) Gross interest expense ................................ $ 13.4 $ 7.0 $ 45.0 $ 21.4 Capitalized interest .................................. (4.0) (2.3) (11.7) (6.6) ------- ------ ------- ------- Net interest expense .................................. 9.4 4.7 33.3 14.8 Distributions on preferred securities ................. -- 2.3 4.6 7.0 ------- ------ ------- ------- Total interest expense and distributions ....... $ 9.4 $ 7.0 $ 37.9 $ 21.8 ======= ====== ======= =======
UNREALIZED COMMODITY DERIVATIVE INCOME (EXPENSE). The $3.6 million and $0.7 million of income for the third quarter and the first nine months of 2003, respectively, primarily represents the hedge ineffectiveness associated with our hedging program and the fair value adjustment for our three-way collar contracts that do not qualify for hedge accounting. The unrealized expense of $14.0 million during the third quarter of 2002 and $25.5 million during the first nine months of 2002 primarily reflect the reversal of the time value gains that were previously recognized during 2001. For a further description of these items, please see Note 11, "Commodity Derivative Instruments and Hedging Activities," to our consolidated financial statements appearing earlier in this report. TAXES. The effective tax rate for the three and nine month periods ended September 30, 2003 and 2002 was about the same. Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices, estimates of the timing and amount of future production and estimates of future operating and capital costs. ADOPTION OF SFAS NO. 143. We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," as of January 1, 2003. This statement changes the method of accounting for expected future costs associated with our obligation to perform site reclamation, dismantle facilities and plug and abandon wells. Prior to January 1, 2003, we recognized the undiscounted estimated cost to abandon our oil and gas properties over their estimated productive lives on a unit-of-production basis as a component of DD&A expense and no liability or capitalized costs associated with such abandonment were recorded on our consolidated balance sheet. SFAS No. 143 requires that, if a reasonable estimate of the fair value of an abandonment obligation can be made, a liability (an "asset retirement obligation" or "ARO") will be recorded on our consolidated balance sheet and the asset retirement cost will be capitalized in oil and gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs will be depreciated on a unit-of-production basis over the productive life of the related properties. Both the accretion and the depreciation are included in DD&A on our consolidated statement of income. At adoption of SFAS No. 143, a cumulative effect of change in accounting principle was required in order to recognize: - an initial ARO as a liability on our consolidated balance sheet; - an increase in oil and gas properties for the cost to abandon our oil and gas properties; - cumulative accretion of the ARO from the period incurred up to the January 1, 2003 adoption date; and - cumulative depreciation on the additional capitalized costs included in oil and gas properties up to the January 1, 2003 adoption date. As a result of our adoption of SFAS No. 143, we recorded a $134.8 million increase in the net capitalized costs of our oil and gas properties and an initial ARO of $128.5 million. Additionally, we recognized an after-tax gain of $5.6 million (the after-tax amount by which additional capitalized costs, net of accumulated depreciation, exceeded the initial ARO, including in each case discontinued operations) for the cumulative effect of change in accounting principle. 23 RESULTS OF DISCONTINUED OPERATIONS On September 5, 2003, we sold our wholly owned subsidiary, Newfield Exploration Australia Ltd., which held all of our Australian assets. As a result of the sale, the historical financial position, results of operations and cash flow of Newfield Exploration Australia Ltd. are reflected in our financial statements as "discontinued operations." Please see Note 2, "Discontinued Operations," to our consolidated financial statements appearing earlier in this report. The results of operations of Newfield Exploration Australia Ltd., which have been reclassified as discontinued operations for the three and nine months ended September 30, 2003 and 2002, are summarized as follows (in thousands):
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------- ------------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Loss on sale of discontinued operations ............... $ (9,895) $ -- $ (9,895) $ -- Income (loss) from discontinued operations before income taxes ............................... 1,318 2,415 (9,881) 2,913 Income tax benefit (provision) ........................ (395) (684) 2,784 (895) -------- -------- -------- -------- Income (loss) from discontinued operations ............ $ (8,972) $ 1,731 $(16,992) $ 2,018 ======== ======== ======== ========
The decrease in earnings from discontinued operations before income taxes for the three months ended September 30, 2003 compared to the same period in 2002 was primarily due to the timing of oil liftings from our FPSOs in 2002 as compared to 2003. The decrease in earnings from discontinued operations before income taxes for the nine months ended September 30, 2003 compared to the same period in 2002 was primarily due to a ceiling test writedown of $7.3 million ($5.1 million after-tax) recorded in the second quarter of 2003 and the timing of oil liftings from our FPSOs in 2002 as compared to 2003. LIQUIDITY AND CAPITAL RESOURCES Our capital budget is established at the beginning of each year. Because of the nature of the properties we own, only a small portion of our capital budget relates to contractual obligations to invest in particular properties. The size of our budget is driven by expected cash flow from operations. 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. Our cash flow from operations during the first nine months of 2003 significantly exceeded our capital expenditures (including the acquisition of Primary Natural Resources) during that period. We used the excess cash flow to pay down debt (see Note 7, "Debt," to our consolidated financial statements appearing earlier in this report and "--Credit Arrangements" and "--Cash Flow used in Continuing Financing Activities" below). We anticipate that our fourth quarter 2003 capital expenditures will be substantially funded by cash flow from operations. To the extent that cash receipts during the quarter are less than capital needs, we will make up the shortfall with borrowings under our credit arrangements. CREDIT ARRANGEMENTS. We maintain our reserve-based revolving credit facility with JPMorgan Chase Manhattan Bank, as agent. The facility matures on January 23, 2005. The banks participating in the facility have committed to lend us 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. The borrowing base is reduced by the principal amount of outstanding senior notes ($300 million at October 31, 2003), 30% of the principal amount of any outstanding senior subordinated notes (a reduction of $75 million at October 31, 2003) and the outstanding principal amount of the secured notes ($3 million at October 31, 2003). The borrowing base will be redetermined at least semi-annually and, prior to reduction for the foregoing items, was $805 million at November 1, 2003. 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. We also have money market lines of credit with various banks. Our credit facility limits our borrowings under these lines to $40 million. At October 31, 2003, we had outstanding borrowings under our credit facility of $129 million and no outstanding borrowings under our money market lines. Consequently, at October 31, 2003, we had approximately $336 million of available capacity under our credit arrangements. 24 At September 30, 2003, the interest rate for our outstanding LIBOR-based loans was 2.5% and for our outstanding money market lines of credit was 3.0%. At December 31, 2002, the interest rate was 2.75% for LIBOR-based loans under our credit facility and 2.50% for the loans outstanding under the money market lines of credit. During September 2003, we entered into interest rate swap agreements that effectively convert the fixed interest rate on a portion of our outstanding senior notes into a variable interest rate (see Note 7, "Debt--Interest Rate Swaps," to our consolidated financial statements appearing earlier in this report and "Item 3. Quantitative and Qualitative Disclosures about Market Risk" appearing later in this report). WORKING CAPITAL. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements. Generally, we use excess cash to pay down borrowings under our credit arrangements. We had a working capital deficit of $13.3 million as of September 30, 2003. This compares to a working capital deficit of $57.0 million as of December 31, 2002. CASH FLOW FROM CONTINUING OPERATIONS. Our net cash from operations for the first nine months of 2003 increased 66% compared to the first nine months of 2002. This increase was primarily due to higher operating income. CAPITAL EXPENDITURES. Our capital spending, including discontinued operations, during the first nine months of 2003 was $482 million, a 95% increase over the same period of last year. During the first nine months of 2003, we invested approximately $150 million in proved property acquisitions, $163 million in U.S. development, $147 million in U.S. exploration, $12 million in other U.S. operations and $10 million internationally. Since the beginning of the year, we have increased our capital budget for 2003 from $450 million to $640 million, including discontinued operations. The budget includes $250 million for U.S. development, $230 million for U.S. exploration, $150 million for proved property acquisitions and $10 million for international projects. These budget amounts broken down by area are approximately 56% U.S. onshore, 42% Gulf of Mexico (including deepwater) and the balance international. Acquisitions are opportunistic and are not budgeted under our capital program unless specifically identified at the time the budget is prepared. We continue to pursue attractive acquisition opportunities; however, the timing, size and purchase price of acquisitions are unpredictable. Historically, we have completed several acquisitions of varying sizes each year, as we have done this year. Depending on the timing of an acquisition, we may spend additional capital during the year of acquisition for drilling and development activities on the acquired properties. CASH FLOW USED IN CONTINUING FINANCING ACTIVITIES. We redeemed all of the outstanding preferred securities of Newfield Financial Trust I on June 27, 2003 for an aggregate redemption price of approximately $148.4 million. We financed the redemption with the net proceeds from the issuance and sale of 3.5 million shares of our common stock (approximately $131.2 million) and borrowings under our revolving credit facility. For a further discussion of these transactions, please see "--Results of Continuing Operations--Redemption of Trust Preferred Securities." During the first nine months of 2003, we either repurchased or repaid $74.3 million principal amount of our secured notes. On March 31, 2003, all of our obligations under the gas forward sales contract with Bob West Treasure L.L.C. and all other agreements related to the gas sales contract were terminated in exchange for a payment by us of approximately $73 million. For a further discussion of this settlement, please see "--Results of Continuing Operations--Gas Sales Obligation Settlement." OIL AND GAS HEDGING We generally hedge a substantial, but varying, portion of our anticipated oil and gas production for the next 18-24 months as part of our risk management program. We use hedging to reduce price volatility, help ensure that we have adequate cash flow to fund our capital programs and manage price risks and return on some of our acquisitions and capital programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. Approximately 83% (on an Mcfe basis) of our production target for the three months ending December 31, 2003 is hedged. 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 counterparties will be unable to meet the financial terms of the transactions. 25 Substantially all of our hedging transactions are settled based upon reported prices on the NYMEX. We believe there is no material basis risk with respect to our natural gas price hedging contracts because substantially all of our hedged natural gas production is sold at market prices that historically have highly correlated to the settlement price. Because substantially all of our U.S. Gulf Coast oil production is sold at current market prices that historically have highly correlated to the NYMEX West Texas Intermediate price, we believe that we have no material basis risk with respect to our oil hedging transactions. The actual cash price we receive, however, generally is about $2.00 per barrel less than the NYMEX West Texas Intermediate price when adjusted for location and quality differences. Please see the discussion and tables in Note 11, "Commodity Derivative Instruments and Hedging Activities," to our consolidated financial statements appearing earlier in this report for a description of the accounting applicable to our hedging program and a listing of open contracts as of September 30, 2003 and the fair value of those contracts as of that date. Between September 30, 2003 and November 3, 2003, we entered into the following transactions.
NYMEX CONTRACT PRICE PER MMBTU ------------------------------------------------------------------------- COLLARS ---------------------------------- ADDITIONAL PUT FLOORS CEILINGS SWAPS ------------------- ----------------- --------------- VOLUME IN (WEIGHTED WEIGHTED WEIGHTED WEIGHTED PERIOD AND TYPE OF CONTRACT MMMBTUS AVERAGE) RANGE AVERAGE RANGE AVERAGE RANGE AVERAGE --------------------------- --------- --------- -------- --------- ----- -------- ----- -------- October 2003 - December 2003 Ceiling contracts............... 1,500 -- -- -- -- -- $6.55 $6.55 January 2004 - December 2004 Price swap contracts............ 15,900 $4.93 -- -- -- -- -- -- Collar contracts................ 2,250 -- -- -- $5.00 $ 5.00 7.50 7.50 3-Way collar contracts.......... 1,350 -- $4.25 $4.25 5.00 5.00 7.00 7.00
NEW ACCOUNTING STANDARDS We adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," as of January 1, 2003. For a discussion of SFAS No. 143 and the effects of our adoption of this statement, please see "--Results of Continuing Operations--Adoption of SFAS No. 143" and Note 1, "Organization and Summary of Significant Accounting Policies--Accounting for Asset Retirement Obligations," to our consolidated financial statements appearing earlier in this report. For a discussion of other recently issued accounting standards and interpretations, please see Note 1, "Organization and Summary of Significant Accounting Policies--Other New Accounting Standards," to our consolidated financial statements appearing earlier in this report. ASSETS HELD FOR SALE As a result of our acquisition of EEX Corporation in November 2002, we own a 60% interest in a floating production system (FPS), some offshore pipelines and a processing facility located at the end of the pipelines in shallow water. The FPS is a combination deepwater drilling rig and processing facility capable of simultaneous drilling and production operations. These infrastructure assets are not currently in service and we do not have a specific use for them in our offshore operations. At the time of acquisition, we estimated their fair market value to be $35 million and classified them as "assets held for sale" under the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement provides that an asset can only be classified as "held for sale" for one year. Therefore, should a sale not occur during the fourth quarter of 2003, these assets must be re-categorized as held in use assets and periodically evaluated for impairment. RECENT DEVELOPMENTS SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that certain intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new guidelines for accounting for goodwill and other intangible assets. Under the statement, goodwill and certain other intangible assets are reviewed annually for impairment but are not amortized. To our knowledge substantially all publicly traded oil and gas companies have continued to include oil and gas rights and interests held under leases, governmental licenses or other contractual arrangements (leasehold interests) as part of oil and gas properties after SFAS No. 141 and SFAS No. 142 became effective. It is our understanding that the staffs of the FASB and the Securities and Exchange Commission may have questioned the oil and gas industry's application of SFAS Nos. 141 and 142 to leasehold interests. 26 Based on our understanding of the SEC's and the FASB's potential interpretation of SFAS Nos. 141 and 142, if all leasehold interests were deemed to be intangible assets, for companies like us that use the full cost method of accounting for oil and gas activities: - leasehold interests with proved reserves that were acquired after June 30, 2001 and leasehold interests with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet; - our results of operations and cash flows would not be affected because leasehold costs would continue to be amortized in accordance with full cost accounting rules; and - the disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements. If SFAS Nos. 141 and 142 were applied as described above, at September 30, 2003 we had undeveloped leasehold interests of approximately $106 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as "intangible undeveloped leaseholds" and we had developed leasehold interests of approximately $620 million (without reduction for depreciation, depletion and amortization) that would be classified on our consolidated balance sheet as "intangible developed leaseholds." We have had no contact with the staff of the FASB or the SEC regarding these matters. The foregoing discussion is based on information provided to us by other industry participants and by members of the accounting and legal profession. We will continue to classify our leasehold interests as tangible oil and gas properties until further guidance is provided. 27 GENERAL INFORMATION General information about us can be found at www.newfld.com. In conjunction with our web page, we also maintain an electronic publication entitled @NFX. @NFX is periodically published to provide updates on our operating activities and our latest publicly announced estimates of expected production volumes, costs and expenses for the then current quarter. Recent editions of @NFX are available on our web page. To receive @NFX directly by email, please forward your email address to info@newfld.com or visit our web page and sign up. Our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. FORWARD-LOOKING INFORMATION This report contains information that is forward-looking or relates to anticipated future events or results such as planned capital expenditures, the availability of capital resources to fund capital expenditures and anticipated cash flow. Although we believe that the expectations reflected in this information are reasonable, this information is 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 and the availability of capital resources. 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, used herein in reference to crude oil or condensate. Bcf. Billion cubic feet. Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil or condensate. 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 or condensate. 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 or condensate. NYMEX. The New York Mercantile Exchange. 28 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risk from changes in oil and gas prices and interest rates as discussed below: OIL AND GAS PRICES Please see the discussion and tables in Note 11, "Commodity Derivative Instruments and Hedging Activities," to our consolidated financial statements appearing earlier in this report and the discussion under the caption "Oil and Gas Hedging," in Item 2 of this report for a description of our hedging program and a listing of open hedging contracts as of September 30, 2003 and the fair value of those contracts as of that date. INTEREST RATES During September 2003, we entered into interest rate swap agreements with respect to a portion of our outstanding senior notes to take advantage of low interest rates and to obtain what we view as a more desirable proportion of variable and fixed rate debt. Under the terms of the interest rate swap contracts with respect to our 7.45% Senior Notes due 2007, we receive a fixed semi-annual rate of 7.45% on $50 million principal amount and pay the counterparties a variable rate equal to the three-month LIBOR, reset quarterly, plus 425 basis points. Under the terms of the interest rate swap contract with respect to our 7 5/8% Senior Notes due 2011, we receive a fixed semi-annual rate of 7.625% on $50 million principal amount and pay the counterparty a variable rate equal to the three-month LIBOR, reset quarterly, plus 349 basis points. We continue to consider our interest rate exposure to be minimal because the majority, about 65%, of our long-term debt obligations were at fixed rates at September 30, 2003. FOREIGN CURRENCY EXCHANGE RATES Our cash flow from certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. We consider our current risk exposure to exchange rate movements, based on net cash flows, to be minimal. We did not have any open derivative contracts relating to foreign currencies at September 30, 2003. ITEM 4. CONTROLS AND PROCEDURES As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-14(c) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that material information is accumulated and communicated to management, and made known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this report. There have been no significant changes in our internal controls or in other factors, which could significantly affect internal controls subsequent to the date we carried out our evaluation. 29 PART II ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits:
Exhibit Number Description -------------- ----------- 31.1 Certification of Chief Executive Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2 Certification of Chief Financial Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certification of Chief Executive Officer of Newfield pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 32.2 Certification of Chief Financial Officer of Newfield pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(b) Reports on Form 8-K: On September 30, 2003, we filed a current report on Form 8-K announcing the issuance of our @NFX publication, which included a summary of our natural gas and crude oil hedge positions as of September 25, 2003. On September 15, 2003, we filed a current report on Form 8-K providing the information required by Regulation BTR with respect to our 401(k) plan. On September 9, 2003, we filed a current report on Form 8-K disclosing information regarding our recent acquisition and divestiture activity, as well as recent drilling results. On July 24, 2003, we filed a current report on Form 8-K announcing our second quarter 2003 financial results and third quarter 2003 guidance regarding production and significant operating and financial data. 30 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 12, 2003 By: /s/ TERRY W. RATHERT --------------------------------------------- Terry W. Rathert Vice President and Chief Financial Officer (Authorized Officer and Principal Financial Officer) 31 EXHIBIT INDEX
Exhibit Number Description -------------- ----------- 31.1 Certification of Chief Executive Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2 Certification of Chief Financial Officer of Newfield pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1 Certification of Chief Executive Officer of Newfield pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 32.2 Certification of Chief Financial Officer of Newfield pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002