================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 1-10537 NUEVO ENERGY COMPANY (Exact Name of Registrant as Specified in Its Charter) DELAWARE 76-0304436 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1021 MAIN, SUITE 2100, HOUSTON, TEXAS 77002 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (713) 652-0706 Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days Yes [X] No[ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock, par value $.01 per share. Shares outstanding on May 8, 2003: 19,247,269. ================================================================================ NUEVO ENERGY COMPANY TABLE OF CONTENTS PAGE ---- PART I Item 1. Financial Statements Condensed Consolidated Statements of Income........................ 3 Condensed Consolidated Balance Sheets.............................. 4 Condensed Consolidated Statements of Cash Flows.................... 5 Condensed Consolidated Statements of Comprehensive Income (Loss)... 6 Notes to the Condensed Consolidated Financial Statements........... 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................................... 15 Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995. 21 Item 3. Quantitative and Qualitative Disclosures About Market Risk............ 22 Item 4 Disclosure Controls and Procedures.................................... 23 PART II Item 1. Legal Proceedings..................................................... 24 Item 2. Changes in Securities and Use of Proceeds............................. 24 Item 3. Defaults Upon Senior Securities....................................... 24 Item 4. Submission of Matters to a Vote of Security-Holders................... 24 Item 5. Other Information..................................................... 24 Item 6. Exhibits and Reports on Form 8-K...................................... 24 Signatures ........................................................... 25 Certifications........................................................ 26 2 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS NUEVO ENERGY COMPANY CONDENSED CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED) Quarter Ended March 31, ----------------------- 2003 2002 -------- -------- Revenues Crude oil and liquids ............................................. $ 82,802 $ 65,251 Natural gas ....................................................... 15,310 5,711 Other ............................................................. 138 6 -------- -------- 98,250 70,968 -------- -------- Costs and Expenses Lease operating expenses .......................................... 39,330 34,626 Exploration costs ................................................. 1,072 1,058 Depreciation, depletion, amortization and accretion ............... 17,389 17,248 General and administrative expenses ............................... 6,717 6,083 Other ............................................................. 795 24 -------- -------- 65,303 59,039 -------- -------- Operating Income ....................................................... 32,947 11,929 Derivative gain (loss) ............................................ (943) (756) Interest income ................................................... 79 108 Interest expense .................................................. (9,322) (9,004) Dividends on TECONS ............................................... (1,653) (1,653) -------- -------- Income From Continuing Operations Before Income Taxes .................. 21,108 624 Income Tax Expense Current ........................................................... 1,504 -- Deferred .......................................................... 6,941 251 -------- -------- 8,445 251 -------- -------- Income From Continuing Operations ...................................... 12,663 373 Income from discontinued operations, including gain/loss on disposal, net of income taxes ................................................. 4,554 1,089 Cumulative effect of a change in accounting principle, net of income tax 8,496 -- -------- -------- Net Income ............................................................. $ 25,713 $ 1,462 ======== ======== Earnings Per Share: Basic Income from continuing operations ................................. $ 0.66 $ 0.02 Income from discontinued operations, net of income taxes .......... 0.24 0.07 Cumulative effect of a change in accounting principle, net of income tax benefit ............................................. 0.44 -- -------- -------- Net income ........................................................ $ 1.34 $ 0.09 ======== ======== Diluted Income from continuing operations ................................. $ 0.65 $ 0.01 Income from discontinued operations, net of income taxes .......... 0.24 0.07 Cumulative effect of a change in accounting principle, net of income tax benefit ........................................... 0.44 -- -------- -------- Net income ........................................................ $ 1.33 $ 0.08 ======== ======== Weighted Average Shares Outstanding: Basic ............................................................. 19,199 17,000 ======== ======== Diluted ........................................................... 19,305 17,176 ======== ======== See accompanying notes. 3 NUEVO ENERGY COMPANY CONDENSED CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE AMOUNTS) March 31, December 31, 2003 2002 ----------- ----------- (UNAUDITED) ASSETS Current assets Cash and cash equivalents ........................................................ $ 73,843 $ 5,047 Accounts receivable, net ......................................................... 60,017 40,945 Inventory ........................................................................ 6,180 7,326 Assets held for sale ............................................................. 48,438 92,738 Deferred income taxes ............................................................ 8,835 7,683 Prepaid expenses and other ....................................................... 2,164 3,862 ----------- ----------- Total current assets ......................................................... 199,477 157,601 ----------- ----------- Property and equipment, at cost Land ............................................................................. 5,224 5,224 Oil and gas properties (successful efforts method) ............................... 989,286 951,258 Other property ................................................................... 14,411 14,303 ----------- ----------- 1,008,921 970,785 Accumulated depreciation, depletion and amortization ............................. (311,662) (357,072) ----------- ----------- Total property and equipment, net ............................................ 697,259 613,713 ----------- ----------- Deferred income taxes ................................................................ 29,164 43,258 Goodwill ............................................................................. 19,664 19,664 Other assets ......................................................................... 23,569 20,935 ----------- ----------- Total assets .............................................................. $ 969,133 $ 855,171 =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable ................................................................. $ 31,114 $ 34,323 Accrued interest ................................................................. 14,431 5,169 Accrued drilling costs ........................................................... 6,802 8,035 Accrued lease operating costs .................................................... 16,840 15,598 Price risk management activities ................................................. 28,234 20,884 Other accrued liabilities ........................................................ 29,829 16,735 Current portion of long-term debt ................................................ 2,367 -- ----------- ----------- Total current liabilities .................................................... 129,617 100,744 ----------- ----------- Long-Term debt Senior Subordinated Notes ........................................................ 407,210 409,577 Bank Credit Facility ............................................................. -- 28,700 ----------- ----------- Total debt ................................................................... 407,210 438,277 Interest rate swaps - fair value adjustment ...................................... 2,392 2,161 Interest rate swaps - termination gain ........................................... 11,383 11,673 ----------- ----------- Long-term debt ............................................................... 420,985 452,111 ----------- ----------- Asset retirement obligation .......................................................... 91,774 -- Other long-term liabilities .......................................................... 14,788 13,040 Company-Obligated Mandatorily Redeemable Convertible Preferred Securities of Nuevo Financing I (TECONS) ............................................................. 115,000 115,000 Commitments and contingencies (Note 9) Stockholders' equity Preferred stock, $1.00 par value, 10,000,000 shares authorized; 7% Cumulative Convertible Preferred Stock, none issued ....................................... -- -- Common stock, $0.01 par value, 50,000,000 shares authorized, 23,073,151 and 23,048,388 shares issued and 19,225,514 and 19,110,102 shares outstanding, ..... 231 230 respectively Additional paid-in capital ....................................................... 389,949 388,479 Treasury stock, at cost, 3,847,639 and 3,867,691 shares, respectively ............ (75,414) (75,683) Deferred stock compensation and other ............................................ (1,708) (605) Accumulated other comprehensive income (loss) .................................... (15,124) (11,468) Accumulated deficit .............................................................. (100,965) (126,677) ----------- ----------- Total stockholders' equity ................................................... 196,969 174,276 ----------- ----------- Total liabilities and stockholders' equity ................................ $ 969,133 $ 855,171 =========== =========== See accompanying notes. 4 NUEVO ENERGY COMPANY CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED) Quarter Ended March 31, ----------------------- 2003 2002 -------- -------- Cash flows from operating activities Net income .................................................. $ 25,713 $ 1,462 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion, amortization and accretion .... 17,389 17,248 Dry hole costs ......................................... 571 90 Amortization of debt financing costs ................... 633 602 Deferred income taxes .................................. 6,941 251 Non-cash effect of discontinued operations ............. 33 2,637 Cumulative effect of a change in accounting principle .. (8,496) -- Other .................................................. 1,560 797 Working capital changes, net of non-cash transactions Accounts receivable .................................... (18,896) 3,765 Accounts payable ....................................... (2,071) (7,813) Accrued liabilities .................................... 6,947 1,000 Other .................................................. 16,810 (409) -------- -------- Net cash provided by operating activities ......... 47,134 19,630 -------- -------- Cash flows from investing activities Additions to oil and gas properties ......................... (16,213) (22,662) Additions to other properties ............................... (672) (1,013) Proceeds from sale of properties ............................ 65,406 -- Other investing activities .................................. 1,841 -- -------- -------- Net cash provided by (used) in investing activities 50,362 (23,675) -------- -------- Cash flows from financing activities Net repayments of credit facility ........................... (28,700) (1,525) Proceeds from exercise of stock options ..................... -- 759 -------- -------- Net cash used in financing activities ............. (28,700) (766) -------- -------- Increase (decrease) in cash and cash equivalents ............... 68,796 (4,811) Cash and cash equivalents Beginning of period ........................................ 5,047 7,110 -------- -------- End of period .............................................. $ 73,843 $ 2,299 ======== ======== See accompanying notes. 5 NUEVO ENERGY COMPANY CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (IN THOUSANDS) (UNAUDITED) Quarter Ended March 31, ----------------------- 2003 2002 -------- -------- Net income ................................................................ $ 25,713 $ 1,462 Unrealized gains (losses) from cash flow hedging activity: Reclassification of initial cumulative effect transition adjustment at original value .................................................... -- (1,662) Reclassification adjustments of settled contracts .................... 9,280 (1,134) Changes in fair value of derivative instruments during the period ... (12,936) (11,710) -------- -------- Other comprehensive income (loss) ............................ (3,656) (14,506) -------- -------- Comprehensive income (loss) ............................................. $ 22,057 $(13,044) ======== ======== See accompanying notes. 6 NUEVO ENERGY COMPANY NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION Our 2002 Annual Report on Form 10-K includes a summary of our significant accounting policies and other disclosures. You should read it in conjunction with this Quarterly Report on Form 10-Q. The financial statements as of March 31, 2003, and for the quarters ended March 31, 2003 and 2002, are unaudited. The balance sheet as of December 31, 2002, is derived from the audited balance sheet filed in the Form 10-K. These financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission and do not include all disclosures required on an annual basis by accounting principles generally accepted in the United States. In our opinion, we have made all adjustments, all of which are of a normal, recurring nature, to fairly present our interim period results. Information for interim periods may not necessarily indicate the results of operations for the entire year. The prior period information also includes reclassifications which were made to conform to the current period presentation. These reclassifications have no effect on our reported net income, cash flows or stockholders' equity. Our accounting policies are consistent with those discussed in our Form 10-K, except as discussed below. You should refer to our Form 10-K for a further discussion of those policies. Amendment of Statement 133 on Derivative Instruments and Hedging Activities. In April 2003, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. The statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. Except for implementation issues that have been effective for fiscal quarters that began prior to June 15, 2003 and should continue to be applied in accordance with their effective dates, this statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The financial statement provisions are effective prospectively, except for forward purchases or sales of when-issued securities or other securities that do not yet exist and in which case SFAS No. 149 should be applied to both existing contracts and new contracts entered into after June 30, 2003. We are currently evaluating the effects of this pronouncement. Accounting for Asset Retirement Obligations. In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement requires a liability to be recorded relating to the eventual retirement and removal of assets used in our business. The liability is discounted to its present value, with a corresponding increase to the related asset value. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this Statement are effective for fiscal years beginning after June 15, 2002. We adopted the provisions of SFAS No. 143 on January 1, 2003 to record our asset retirement obligation to plug and abandon oil and gas wells. In connection with the initial application of SFAS No. 143, we recorded a cumulative effect of change in accounting principle, net of taxes, of $8.5 million as an increase to net income. In addition, we recorded an asset retirement obligation for oil and gas properties and equipment of $87.8 million. The following table summarizes asset retirement obligation transactions recorded in accordance with the provisions of SFAS No. 143: Quarter Ended March 31, 2003 -------------- (In thousands) Beginning asset retirement obligation............ $ 87,828 Liabilities incurred during period............... 2,304 Liabilities settled during period................ (481) Accretion expense................................ 2,123 -------------- Ending asset retirement obligation............... $ 91,774 ============== 7 The following table summarizes the pro forma basis as required by SFAS No. 143, had we adopted the provisions of SFAS No. 143 prior to January 1, 2003, the amount of the asset retirement obligations would have been as follows: Pro Forma Asset Retirement Adoption Date Obligation ------------- ---------------- (In thousands) January 1, 2000................. $ 65,621 December 31, 2000............... 72,706 December 31, 2001............... 80,062 March 31, 2002.................. 81,687 December 31, 2002............... 87,828 In addition, pro forma net income and earnings per share for the three months ended March 31, 2002 and for the years ended December 31, 2002, 2001 and 2000 for the change in accounting had it been implemented during the periods: 1st Qtr 2002 2002 2001 2000 ---------- ---------- ---------- ---------- (In thousands, except per share data) Net income As Reported ............... $ 1,462 $ 12,275 $ (79,171) $ 11,635 Pro Forma ................. 2,750 14,897 (75,479) 11,624 Net income per share - Reported Basic ..................... 0.09 0.70 (4.73) 0.67 Diluted ................... 0.08 0.69 (4.73) 0.64 Net income per share - Pro Forma Basic ..................... 0.16 0.84 (4.51) 0.67 Diluted ................... 0.16 0.84 (4.51) 0.65 Guarantor's Accounting and Disclosure Requirements. In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others, which clarifies the requirements of SFAS No. 5, Accounting for Contingencies, relating to a guarantor's accounting for and disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 3, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively, and we cannot reasonably estimate the impact of FIN 45 until guarantees are issued or modified in future periods, at which time their results will be initially reported in the financial statements. Consolidation of Variable Interest Entities. In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"), Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51. FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have no contractual relationship or other business relationship with a variable interest entity and therefore the adoption of FIN 46 will have no effect on our consolidated financial position, results of operations or cash flows. 8 2. STOCK-BASED COMPENSATION We account for stock compensation plans under the intrinsic value method of Accounting Principles Board Opinion ("APB") No. 25, Accounting for Stock Issued to Employees. No compensation expense is recognized for stock options that had an exercise price equal to their market value of the underlying common stock on the date of grant. As permitted by SFAS No. 123, Accounting for Stock-Based Compensation, we have continued to apply APB Opinion No. 25 for purposes of determining net income. Had compensation expense for stock-based compensation been determined based on the fair value at the date of grant, our net income and earnings per share would have been as follows: Quarter Ended March 31, ------------------------ 2003 2002 ---------- ---------- (In thousands, except per share data) Net income as reported ................................................... $ 25,713 $ 1,462 Add: Stock based employee compensation expense included in reported net income, net of related income tax ...................... 178 152 Deduct: Total stock based employee compensation expense determined under fair value based method for all awards, net of related income tax ........ (225) (1,113) ---------- ---------- Pro forma net income ..................................................... $ 25,666 $ 501 ========== ========== Earnings per share: Basic - as reported ................................................. $ 1.34 $ 0.09 Basic - pro forma ................................................... 1.34 0.03 Diluted - as reported ............................................... $ 1.33 $ 0.08 Diluted - pro forma ................................................. 1.33 0.03 3. EARNINGS PER SHARE SFAS No. 128, Earnings per Share, requires a reconciliation of the numerator (income) and denominator (shares) of the basic earnings per share computation to the numerator and denominator of the diluted earnings per share computation. The reconciliation is as follows: Quarter Ended March 31, -------------------------------------- 2003 2002 ----------------- ------------------ Net Net Income Shares Income Shares ------- ------ ------- ------ (In thousands) Earnings - Basic ..................... $25,713 19,199 $ 1,462 17,000 Effect of dilutive securities Stock options and restricted stock -- 106 -- 122 Shares held by benefit trust ..... -- -- (38) 54 ------- ------ ------- ------ Earnings - Diluted ................... $25,713 19,305 $ 1,424 17,176 ======= ====== ======= ====== 4. DISCONTINUED OPERATIONS Brea-Olinda. In February 2003, we sold our Brea-Olinda field located in California for approximately $59.0 million less purchase price adjustments of $2.4 million. Historical results of operations from this property are classified as discontinued operations in our statements of income. Revenues associated with these properties were $3.2 million in the three months ended March 31, 2003 and $3.4 million in the same period of 2002. Pre-tax income associated with these properties was $2.6 million in the three months ended March 31, 2003 and $1.1 million in the same period of 2002. 9 Union Island. In March 2003, we sold our Union Island field located in California for approximately $10.5 million less purchase price adjustments of $1.7 million and recognized a gain on the sale of $7.7 million. Revenues associated with these properties were $1.5 million in the three months ended March 31, 2003 and $0.6 million in the same period of 2002. Pre-tax income associated with these properties was $1.3 million in the three months ended March 31, 2003 and $0.4 million in the same period of 2002. Orcutt Hill. In the first quarter 2003, our Board approved the sale of our Orcutt Hill field located in California. We transferred the remaining basis in this field to assets held for sale and recognized a $5.3 million loss in connection with writing down the basis to the estimated fair value less our costs to sell. Revenues associated with these properties were $2.7 million in the three months ended March 31, 2003 and $1.7 million in the same period of 2002. Pre-tax income associated with these properties was $1.3 million in the three months ended March 31, 2003 and $0.1 million in the same period of 2002. Eastern Properties. In 2002, we sold a majority of our oil and gas properties located in Texas, Alabama and Louisiana. Historical results of operations from these properties are classified as discontinued operations in our consolidated statements of income. Revenues associated with these properties were $1.5 million and pre-tax income was $0.3 million in the three months ended March 31, 2002. 5. PRO FORMA SUMMARY INFORMATION - ACQUISITION OF ATHANOR On September 18, 2002, we acquired Athanor Resources, Inc. (Athanor) for $61.3 million in cash, the issuance of approximately $20.1 million of our common stock (approximately 2.0 million shares) and the assumption of net liabilities with a fair value of approximately $20.0 million. The following unaudited pro forma condensed income statement information has been prepared to give effect to the merger as if the transaction had occurred at the beginning of the period presented. The historical results of operations, based on first quarter 2002 realized prices, have been adjusted to reflect the difference between Athanor's historical depletion, depreciation and amortization and such expense calculated based on the value allocated to the assets acquired in the merger. The information presented is not necessarily indicative of the results of future operations of the merged companies. Quarter Ended March 31, 2002 -------------- (In thousands, except per share data) Revenues ......................................................... $ 75,261 Income from continuing operations ................................ 639 Net income ....................................................... 1,728 Earnings per share Basic Income from continuing operations ......................... $ 0.03 Net income ................................................ 0.09 Diluted Income from continuing operations ......................... $ 0.03 Net income ................................................ 0.09 10 6. LONG-TERM DEBT Our long-term debt consists of the following: March 31, December 31, 2003 2002 --------- ------------ (In thousands) 9 3/8% Senior Subordinated Notes due 2010 ....... $ 150,000 $ 150,000 9 1/2% Senior Subordinated Notes due 2008 ....... 257,210 257,210 9 1/2% Senior Subordinated Notes due 2006 ....... 2,367 2,367 Bank credit facility (3.81% on December 31, 2002) -- 28,700 --------- ------------ Total debt .................................. 409,577 438,277 Interest rate swaps - fair value adjustment ..... 2,392 2,161 Interest rate swaps - termination gain .......... 11,383 11,673 --------- ------------ Total debt and interest rate swaps .............. 423,352 452,111 Less current portion of long-term debt .......... (2,367) -- --------- ------------ Long-term debt .................................. $ 420,985 $ 452,111 ========= ============ We called our 9 1/2% Senior Subordinated Notes due 2006 and completed the redemption in April 2003. 7. FINANCIAL INSTRUMENTS We have entered into commodity swaps, collars, put options and interest rate swaps. The commodity swaps, collars and put options are designated as cash flow hedges and the interest rate swaps are designated as fair value hedges in accordance with SFAS No. 133. Quantities covered by the commodity swaps and put options are based on West Texas Intermediate ("WTI") barrels. Our production is expected to average 74% of WTI, therefore, each WTI barrel hedges 1.36 barrels of our production. Derivative Instruments Designated as Cash Flow Hedges At March 31, 2003, we had entered into the following cash flow hedges: Crude Oil Natural Gas ---------------------------------------- ------------------------------------- Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index ----------- ------------- -------- --------- ----------- --------- Swaps for Sales --------------- 2003 2nd Qtr. 14,500 $ 23.85 WTI 4,000 $ 4.38 Waha 3rd Qtr. 13,500 23.62 WTI 4,000 4.41 Waha 4th Qtr. 13,000 23.68 WTI 4,000 4.38 Waha 2004 1st Qtr. 13,500 23.56 WTI 8,000 4.34 Waha 2nd Qtr. 11,500 23.82 WTI 3,000 3.91 Waha 3rd Qtr. 9,500 23.50 WTI 3,000 3.91 Waha 4th Qtr. 4,500 22.82 WTI 3,000 3.91 Waha 2005 Full Year 4,500 22.14 WTI Collars ------- 2003 Full Year 10,000 22.00 - 28.91 WTI 2nd Qtr. - 4th Qtr. 6,000 3.70-4.30 Waha Swaps for Purchases ------------------- 2004 8,000 3.91 Socal 2005 8,000 3.85 Socal 11 Derivative Instruments Designated as Fair Value Hedges. In late December 2001 and early 2002, we entered into three interest rate swap agreements with notional amounts totaling $200.0 million to hedge the fair value of our 9 -1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These swaps were designated as fair value hedges and were reflected as an increase or decrease of long-term debt with a corresponding increase in long-term assets or liabilities. In late August and early September 2002, we terminated our swap transactions relating to these Notes. As a result of these terminations, we received accrued interest of $2.2 million and the present value of the swap option of $9.6 million on our 9 3/8% Notes and $0.5 million in accrued interest and the present value of the swap option of $2.5 million on our 9 -1/2% Notes. The gain of $9.6 million on our 9 3/8% Notes and $2.5 million on our 9 -1/2% Notes is reflected as an increase of long-term debt is being amortized as a periodic reduction in interest expense over the life of the Notes. During the three months ended March 31, 2003, we amortized $0.3 million as a reduction of interest expense. In late August and early November 2002, we entered into two interest rate swap agreements with notional amounts totaling $100.0 million, to hedge a portion of the fair value of our 9 3/8% Notes due 2010. These swaps are designated as fair value hedges and are reflected as an increase of long-term debt of $2.4 million as of March 31, 2003, with a corresponding increase in long-term assets. Under the terms of the first agreement, the counterparty pays us a weighted average fixed annual rate of 9 3/8% on total notional amounts of $50.0 million, and we pay the counterparty a variable annual rate equal to the six-month LIBOR rate plus a weighted average rate of 4.71%. Under the terms of the second agreement, the counterparty pays us a weighted average fixed annual rate of 9 3/8% on total notional amounts of $50.0 million, and we pay the counterparty a variable annual rate equal to the six-month LIBOR rate plus a weighted average rate of 4.95%. Other - Call Spreads. We have a call spread that is not designated as a hedging instrument and is marked-to-market with changes in fair value recognized currently as a derivative gain/loss. During the three months ended March 31, 2003 we recorded a $0.9 million derivative loss and recorded the fair value of the remaining derivative loss at March 31, 2003 totaling $3.7 million in accrued liabilities. 8. SEGMENTS Our operations consist of the acquisition, exploitation, exploration, development and production of crude oil and natural gas. Our reportable segments are domestic, foreign and other. Financial information by reportable segment is presented below: For the Quarter Ended March 31, 2003 --------------------------------------------------- Oil and Gas Oil and Gas Domestic Foreign Other (1) Total ----------- ----------- --------- -------- (In thousands) Revenues from external customers .. $ 86,631 $ 11,481 $ 138 $ 98,250 Operating income before income tax 35,302 5,650 (19,844) 21,108 For the Quarter Ended March 31, 2002 --------------------------------------------------- Oil and Gas Oil and Gas Domestic Foreign Other (1) Total ----------- ----------- --------- -------- (In thousands) Revenues from external customers.. $ 63,537 $ 7,425 $ 6 $ 70,968 Operating income before income tax 16,283 2,371 (18,030) 624 ---------- (1) Other includes corporate income and expenses. 12 9. COMMITMENTS AND CONTINGENCIES We acquired properties from Unocal and are obligated to make a contingent payment through 2004 if oil prices exceed thresholds set forth in the agreement with Unocal. Contingent payments are accounted for as a purchase price adjustment to oil and gas properties. We paid $10.8 million to Unocal in 2002 attributable to calendar year 2001 and recorded the payment in oil and gas properties. In March 2003, we advised Unocal that we had failed to take deductions to the purchase price that we believe are permitted by the agreement. Application of these deductions result in no payment due for either calendar year 2001 or 2002. Unocal disputes this position for both years and discussions are ongoing in an effort to resolve this issue. While the outcome of this matter is not presently determinable, its resolution is not expected to have a significant impact on our operating results, financial condition or liquidity. On December 18, 2002, a lawsuit was filed by Hills for Everyone, a non-profit corporation, against Orange County and us challenging the adequacy of the Environment Impact Report for the Company's Tonner Hills real estate project. The suit seeks to compel Orange County to set aside its decision to adopt the Environment Impact Report and seeks additional environmental analysis and mitigation measures. We are contesting the litigation and both the county and we are continuing to take the necessary regulatory steps to move the project toward development. On June 15, 2001, we experienced a failure of a carbon dioxide treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura County, California. There were no injuries associated with this event. Crude oil and natural gas produced from three fields offshore California are transported onshore by pipeline to the ROSF plant where crude oil and water are separated and treated, and carbon dioxide is removed from the natural gas stream. The daily net production associated with these fields was 3,000 barrels of crude oil and 2.4 MMcf of natural gas in 2001, representing approximately 6% of our daily production. In early July 2001, crude oil production resumed and full gas sales resumed by mid August 2001. The cost of repair and business interruption (less a 30-day waiting period) are expected to be covered by insurance. We expect to settle the insurance claims within the next three months. In September 1997, there was a spill of crude oil into the Santa Barbara Channel from a pipeline that connects our Point Pedernales field with shore-based processing facilities. The volume of the spill was estimated to be 163 Bbls of oil. Repairs were completed by the end of 1997, and production recommenced in December 1997. The costs of the clean up and the cost to repair the pipeline either have been or are expected to be covered by our insurance, less a deductible of $0.1 million. As of March 31, 2003, we had received insurance reimbursements of $4.2 million, with a remaining insurance receivable of $0.5 million. Costs related to the settlement of claims for natural resource damage asserted by certain federal and state agencies were covered by insurance. Our international investments involve risks typically associated with investments in emerging markets such as an uncertain political, economic, legal and tax environment and expropriation and nationalization of assets. In addition, if a dispute arises in our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the United States. We attempt to conduct our business and financial affairs to protect against political and economic risks applicable to operations in the various countries where we operate, but there can be no assurance that we will be successful in so protecting ourselves. A portion of our investment in the Congo is insured through political risk insurance provided by Overseas Private Investment Corporation ("OPIC"). The political risk insurance through OPIC covers up to $25.0 million relating to expropriation and political violence, which is the maximum coverage available through OPIC. In connection with our February 1995 acquisitions of two subsidiaries owning interests in the Yombo field offshore Congo, we and a wholly-owned subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the subsidiaries not to claim certain tax losses ("dual consolidated losses") incurred by such subsidiaries prior to the acquisitions. Under the tax law in the Congo, as it existed when this acquisition took place, if an entity is acquired in its entirety and that entity has certain tax attributes, for example tax loss carry forwards from operations in the Republic of Congo, the subsequent owners of that entity can continue to utilize those losses without restriction. Pursuant to the agreement, we and CMS may be liable to the seller for the recapture of dual consolidated losses (net operating losses of any domestic corporation that are subject to an income tax of a foreign country without regard to the source of its income or on a residence basis) utilized by the 13 seller in years prior to the acquisitions if certain triggering events occur, including: (i) a disposition by either us or CMS of its respective Congo subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo field, (iii) the acquisition of us or CMS by another consolidated group or (iv) the failure of CMS's Congo subsidiary or us to continue as a member of its respective consolidated group. A triggering event will not occur, however, if a subsequent purchaser enters into certain agreements specified in the consolidated return regulations intended to ensure that such dual consolidated losses will not be claimed. The only time limit associated with the occurrence of a triggering event relates to the utilization of a dual consolidated loss in a foreign jurisdiction. A dual consolidated loss that is utilized to offset income in a foreign jurisdiction is only subject to recapture for 15 years following the year in which the dual consolidated loss was incurred for U.S. income tax purposes. We and CMS have agreed among ourselves that the party responsible for the triggering event shall indemnify the other for any liability to the seller as a result of such triggering event. Our potential direct liability could be as much as $35.4 million if a triggering event with respect to us occurs. Additionally, we believe that CMS's liability (for which we would be jointly liable with an indemnification right against CMS) could be as much as $53.1 million. CMS sold their interest in the Yombo field in 2002 to a U.S. subsidiary of Perenco, S.A. (Perenco). The sale was not a triggering event as both CMS and Perenco filed a request for a Closing Agreement with the Internal Revenue Service in accordance with the U.S. consolidated tax return regulations prior to the sale. Further, we do not expect a triggering event to occur with respect to Nuevo, CMS or Perenco, and do not believe the agreement will have a material adverse effect upon us. 14 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS Our results of operations are significantly affected by fluctuations in oil and gas prices. The following table reflects our production and average prices for oil and natural gas: Quarter Ended March 31, ------------------------ 2003 2002 -------- ---------- Crude Oil and Liquids Sales Volumes (MBbls/day) Domestic ................................... 37.2 37.7 Foreign .................................... 4.9 5.0 -------- ---------- Total ................................... 42.1 42.7 ======== ========== Sales Prices ($/Bbl) Unhedged ................................... $ 25.51 $ 15.77 Hedged ..................................... 21.83 16.99 Revenues ($/thousands) Domestic ................................... $ 85,271 $ 53,337 Foreign .................................... 11,481 7,425 Marketing Fees ............................. (4) (194) Hedging .................................... (13,946) 4,683 -------- ---------- Total ................................. $ 82,802 $ 65,251 ======== ========== Natural Gas Sales Volumes (MMcf/day) Domestic ................................... 39.4 28.4 ======== ========== Sales Prices ($/Mcf) Unhedged ................................... $ 4.80 $ 2.23 Hedged ..................................... 4.32 2.23 Revenues ($/thousands) Domestic ................................... $ 17,106 $ 5,799 Marketing Fees ............................. (93) (88) Hedging .................................... (1,703) -- -------- ---------- Total ................................. $ 15,310 $ 5,711 ======== ========== ---------- Below is a list of terms commonly used in the oil and gas industry. /d = per day Bbl = barrel of crude oil or other liquid hydrocarbons Bcf = billion cubic feet of natural gas Bcfe = billion cubic feet of natural gas equivalent BOE = barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil BOPD = barrel of oil per day MBbl = thousand barrels Mcf = thousand cubic feet of natural gas MMBbl = million barrels of oil or other liquid hydrocarbons MMcf = million cubic feet of natural gas MBOE = thousand barrels of oil equivalent MMBOE = million barrels of oil equivalent 15 QUARTER ENDED MARCH 31, 2003 COMPARED TO QUARTER ENDED MARCH 31, 2002 We had net income of $25.7 million, or $1.33 per diluted share for the quarter ended March 31, 2003 as compared to net income of $1.5 million, or $0.08 per diluted share in the same period of 2002. Revenues Oil and Gas Revenues. Oil and gas revenues increased 38% to $98.1 million for the three months ended March 31, 2003 from $71.0 million in the same period of 2002 due to higher realized crude oil and natural gas prices and higher natural gas production which was partially offset by higher hedging losses in 2003. Crude oil production averaged 42.1 MBbls/day for the three months ended March 31, 2003 compared to 42.7 MBbls/day in the same period of 2002 primarily due to lower production offshore California due to mechanical downtime. The realized oil price for the three months ended March 31, 2003 was $21.83 per Bbl, an increase of $4.84 per Bbl from the same period in 2002. We had hedging losses of $13.9 million in the three months ended March 31, 2003 compared to hedging gain of $4.7 million in same period of 2002. Natural gas production averaged 39.4 MMcf per day for the three months ended March 31, 2003 compared to 28.4 MMcf per day for the same period of 2002. The increase was primarily due to production from the Pakenham field which was acquired in September 2002. The realized natural gas price for the three months ended March 31, 2003 was $4.32 per Mcf, an increase of $2.09 per Mcf from the comparable period in 2002. In the three months ended March 31, 2003, we had gas hedging losses of $0.48 per Mcf. We had no gas hedged in the 2002 period. Costs and Expenses Costs and Expenses. Lease operating expenses ("LOE") for the three months ended March 31, 2003 totaled $39.3 million, as compared to $34.6 million for the 2002 period. The increased LOE was due to higher steam costs in our onshore California operations and costs from our Pakenham field which was purchased in 2002. Exploration costs were $1.1 million in both the three months ended March 31, 2003 and 2002. Exploration costs in 2003 included dry hole cost of the Chott Fejaj well in Tunisia while the 2002 costs were primarily seismic costs. Depletion, depreciation, amortization and accretion ("DD&A") of $17.4 million for the three months ended March 31, 2003, increased $0.2 million from the same period of 2002 primarily due to higher natural gas production and accretion expense related to the January 2003 adoption of SFAS 143. The DD&A rate was $3.97 per BOE in the 2003 period compared to $4.04 per BOE in 2002. General and administrative expense of $6.7 million in 2003 was $0.6 million higher than the comparable period in 2002 due to higher employee costs, severance and insurance in 2003. Derivative Gain (Loss). Our derivative loss for the quarter ended March 31, 2003 was $0.9 million compared to a loss of $0.8 million in the same period of 2002. The derivative loss is comprised of a loss on our mark-to-market derivatives and the ineffective portion of certain of our hedges. Interest Expense. Interest expense was $9.3 million for the three months ended March 31, 2003 compared to interest expense of $9.0 million in the same period of 2002. Lower interest expense on the line of credit of $0.3 million and lower facility fees of $0.2 million were more than offset by a lower benefit on the interest rate swaps of $0.9 million which was due to lower debt swapped in 2003. Dividends. Dividends on the TECONS were $1.7 million in both the three months ended March 31, 2003 and 2002. The TECONS pay dividends at a rate of 5.75% and were issued in December 1996. Income Tax. We had income tax expense of $8.4 million including current tax of $1.5 million for the three months ended March 31, 2003 compared to an expense of $0.3 million in the prior year period which had no current tax. The current tax relates to income tax in California, which deferred the use of net operating losses in 2002 and 2003, and Federal income tax. Our effective income tax rate was 40.0% in 2003 and 40.1% in 2002. Discontinued Operations. We had income from discontinued operations of $4.6 million for the three months ended March 31, 2003 compared to income of $1.1 million in same period of 2002. In 2003, we sold our Brea-Olinda and Union Island properties located onshore California and made the decision to sell our Orcutt Hill property located onshore California. We recognized a $7.7 million gain on the sale of the Union Island property 16 and a $5.4 million loss in connection with writing down the Orcutt Hill property to its estimated fair value less its costs to sell. In 2002 the income from discontinued operations consists of after-tax operating income from our Eastern fields which were sold in 2001 and operating income from our Brea-Olinda, Union Island and Orcutt Hill properties. Cumulative Effect of Change in Accounting Principle. In January 2003, we adopted Statement of Financial Accounting Standards ("SFAS") No. 143. In connection with the initial application, we recorded a cumulative effect of change in accounting principle, net of taxes, of $8.5 million as an increase to income. (See Note 1 to the Condensed Consolidated Financial Statements). CAPITAL RESOURCES AND LIQUIDITY We have grown and diversified our operations through acquisitions of oil and gas properties and the subsequent exploitation and development of these properties. We have historically funded our operations and acquisitions with operating cash flows, bank financing, private and public placements of debt and equity securities, property divestitures and joint ventures with industry participants. Net cash provided by operating activities was $47.1 million for the quarter ended March 31, 2003. In 2003, we invested $16.2 million in oil and gas properties and $0.7 million on other properties. We also received $65.4 million in proceeds from the sale of properties during the quarter ended March 31, 2003. We believe our working capital, cash flow from operations and available financing sources are sufficient to meet our obligations as they become due and to finance our capital budget through 2003. We have a $150 million borrowing base under our Credit Agreement. Under the most restrictive covenant, the entire $150 million was available at March 31, 2003 and we had no borrowings outstanding. We have one letter of credit of $0.8 million under our Credit Agreement. We have interest rate swaps totaling $100 million on our 9 3/8 % Notes due 2010. CONTINGENCIES AND OTHER MATTERS We acquired properties from Unocal and are obligated to make a contingent payment through 2004 if oil prices exceed thresholds set forth in the agreement with Unocal. Contingent payments are accounted for as a purchase price adjustment to oil and gas properties. We paid $10.8 million to Unocal in 2002 attributable to calendar year 2001 and recorded the payment in oil and gas properties. In March 2003, we advised Unocal that we had failed to take deductions to the purchase price that we believe are permitted by the agreement. Application of these deductions result in no payment due for either calendar year 2001 or 2002. Unocal disputes this position for both years and discussions are ongoing in an effort to resolve this issue. While the outcome of this matter is not presently determinable, its resolution is not expected to have a significant impact on our operating results, financial condition or liquidity. On December 18, 2002, a lawsuit was filed by Hills for Everyone, a non-profit corporation, against Orange County and us challenging the adequacy of the Environment Impact Report for the Company's Tonner Hills real estate project. The suit seeks to compel Orange County to set aside its decision to adopt the Environment Impact Report and seeks additional environmental analysis and mitigation measures. We are contesting the litigation and both the county and we are continuing to take the necessary regulatory steps to move the project toward development. On June 15, 2001, we experienced a failure of a carbon dioxide treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura County, California. There were no injuries associated with this event. Crude oil and natural gas produced from three fields offshore California are transported onshore by pipeline to the ROSF plant where crude oil and water are separated and treated, and carbon dioxide is removed from the natural gas stream. The daily net production associated with these fields was 3,000 barrels of crude oil and 2.4 MMcf of natural gas in 2001, representing approximately 6% of our daily production. In early July 2001, crude oil production resumed and full gas sales resumed by mid August 2001. The cost of repair and business interruption (less a 30-day waiting period) are expected to be covered by insurance. We expect to settle the insurance claims within the next three months. In September 1997, there was a spill of crude oil into the Santa Barbara Channel from a pipeline that connects our Point Pedernales field with shore-based processing facilities. The volume of the spill was estimated 17 to be 163 Bbls of oil. Repairs were completed by the end of 1997, and production recommenced in December 1997. The costs of the clean up and the cost to repair the pipeline either have been or are expected to be covered by our insurance, less a deductible of $0.1 million. As of March 31, 2003, we had received insurance reimbursements of $4.2 million, with a remaining insurance receivable of $0.5 million. Costs related to the settlement of claims for natural resource damage asserted by certain federal and state agencies were covered by insurance. Our international investments involve risks typically associated with investments in emerging markets such as an uncertain political, economic, legal and tax environment and expropriation and nationalization of assets. In addition, if a dispute arises in our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the United States. We attempt to conduct our business and financial affairs to protect against political and economic risks applicable to operations in the various countries where we operate, but there can be no assurance that we will be successful in so protecting ourselves. A portion of our investment in the Congo is insured through political risk insurance provided by Overseas Private Investment Corporation ("OPIC"). The political risk insurance through OPIC covers up to $25.0 million relating to expropriation and political violence, which is the maximum coverage available through OPIC. In connection with our February 1995 acquisitions of two subsidiaries owning interests in the Yombo field offshore Congo, we and a wholly-owned subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the subsidiaries not to claim certain tax losses ("dual consolidated losses") incurred by such subsidiaries prior to the acquisitions. Under the tax law in the Congo, as it existed when this acquisition took place, if an entity is acquired in its entirety and that entity has certain tax attributes, for example tax loss carry forwards from operations in the Republic of Congo, the subsequent owners of that entity can continue to utilize those losses without restriction. Pursuant to the agreement, we and CMS may be liable to the seller for the recapture of dual consolidated losses (net operating losses of any domestic corporation that are subject to an income tax of a foreign country without regard to the source of its income or on a residence basis) utilized by the seller in years prior to the acquisitions if certain triggering events occur, including: (i) a disposition by either us or CMS of its respective Congo subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo field, (iii) the acquisition of us or CMS by another consolidated group or (iv) the failure of CMS's Congo subsidiary or us to continue as a member of its respective consolidated group. A triggering event will not occur, however, if a subsequent purchaser enters into certain agreements specified in the consolidated return regulations intended to ensure that such dual consolidated losses will not be claimed. The only time limit associated with the occurrence of a triggering event relates to the utilization of a dual consolidated loss in a foreign jurisdiction. A dual consolidated loss that is utilized to offset income in a foreign jurisdiction is only subject to recapture for 15 years following the year in which the dual consolidated loss was incurred for U.S. income tax purposes. We and CMS have agreed among ourselves that the party responsible for the triggering event shall indemnify the other for any liability to the seller as a result of such triggering event. Our potential direct liability could be as much as $35.4 million if a triggering event with respect to us occurs. Additionally, we believe that CMS's liability (for which we would be jointly liable with an indemnification right against CMS) could be as much as $53.1 million. CMS sold their interest in the Yombo field in 2002 to a U.S. subsidiary of Perenco, S.A. (Perenco). The sale was not a triggering event as both CMS and Perenco filed a request for a Closing Agreement with the Internal Revenue Service in accordance with the U.S. consolidated tax return regulations prior to the sale. Further, we do not expect a triggering event to occur with respect to Nuevo, CMS or Perenco, and do not believe the agreement will have a material adverse effect upon us. NEW ACCOUNTING PRONOUNCEMENTS Amendment of Statement 133 on Derivative Instruments and Hedging Activities. In April 2003, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. The statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. Except for implementation issues that have been effective for fiscal quarters that began prior to June 15, 2003 and should continue to be applied in accordance with their effective dates, this statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The financial statement provisions are effective prospectively, except for forward purchases or sales of when-issued securities or 18 other securities that do not yet exist and in which case SFAS No. 149 should be applied to both existing contracts and new contracts entered into after June 30, 2003. We are currently evaluating the effects of this pronouncement. Accounting for Asset Retirement Obligations. In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement requires a liability to be recorded relating to the eventual retirement and removal of assets used in our business. The liability is discounted to its present value, with a corresponding increase to the related asset value. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. The provisions of this Statement are effective for fiscal years beginning after June 15, 2002. We adopted the provisions of SFAS No. 143 on January 1, 2003 to record our asset retirement obligation to plug and abandon oil and gas wells. In connection with the initial application of SFAS No. 143, we recorded a cumulative effect of change in accounting principle, net of taxes, of $8.5 million as an increase to net income. In addition, we recorded an asset retirement obligation for oil and gas properties and equipment of $87.8 million. The following table summarizes asset retirement obligation transactions recorded in accordance with the provisions of SFAS No. 143: Quarter Ended March 31, 2003 ------------------ (In thousands) Beginning asset retirement obligation............ $ 87,828 Liabilities incurred during period............... 2,304 Liabilities settled during period................ (481) Accretion expense................................ 2,123 ------------------ Ending asset retirement obligation............... $ 91,774 ================== The following table summarizes the pro forma basis as required by SFAS No. 143, had we adopted the provisions of SFAS No. 143 prior to January 1, 2003, the amount of the asset retirement obligations would have been as follows: Pro Forma Asset Retirement Adoption Date Obligation ------------- ---------------- (In thousands) January 1, 2000................. $ 65,621 December 31, 2000............... 72,706 December 31, 2001............... 80,062 March 31, 2002.................. 81,687 December 31, 2002............... 87,828 In addition, pro forma net income and earnings per share for the three months ended March 31, 2002 and for the years ended December 31, 2002, 2001 and 2000 for the change in accounting had it been implemented during the periods: 1st Qtr 2002 2002 2001 2000 ---------- ---------- ---------- ---------- (In thousands, except per share data) Net income As Reported $ 1,462 $ 12,275 $ (79,171) $ 11,635 Pro Forma 2,750 14,897 (75,479) 11,624 Net income per share - Reported Basic 0.09 0.70 (4.73) 0.67 Diluted 0.08 0.69 (4.73) 0.64 Net income per share - Pro Forma Basic 0.16 0.84 (4.51) 0.67 Diluted 0.16 0.84 (4.51) 0.65 19 Guarantor's Accounting and Disclosure Requirements. In November 2002, the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others, which clarifies the requirements of SFAS No. 5, Accounting for Contingencies, relating to a guarantor's accounting for and disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 3, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively, and we cannot reasonably estimate the impact of FIN 45 until guarantees are issued or modified in future periods, at which time their results will be initially reported in the financial statements. Consolidation of Variable Interest Entities. In January 2003, the FASB issued Interpretation No. 46 ("FIN 46"), Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51. FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have no contractual relationship or other business relationship with a variable interest entity and therefore the adoption of FIN 46 will have no effect on our consolidated financial position, results of operations or cash flows. 20 CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 This report contains or incorporates by reference forward looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this document, including without limitation, statements in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations regarding our financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives of our management for future operations and covenant compliance, are forward looking statements. We can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct. Important factors that could cause actual results to differ materially from our expectations are included throughout this document. The cautionary statements expressly qualify all subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf. 21 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information contained in this item updates, and should be read in conjunction with Part II, Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2002. At March 31, 2003, we had entered into the following cash flow hedges: Crude Oil Natural Gas ---------------------------------------- ------------------------------------ Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index ----------- -------------- ------- --------- ---------- --------- Swaps for Sales --------------- 2003 2nd Qtr. 14,500 $ 23.85 WTI 4,000 $ 4.38 Waha 3rd Qtr. 13,500 23.62 WTI 4,000 4.41 Waha 4th Qtr. 13,000 23.68 WTI 4,000 4.38 Waha 2004 1st Qtr. 13,500 23.56 WTI 8,000 4.34 Waha 2nd Qtr. 11,500 23.82 WTI 3,000 3.91 Waha 3rd Qtr. 9,500 23.50 WTI 3,000 3.91 Waha 4th Qtr. 4,500 22.82 WTI 3,000 3.91 Waha 2005 Full Year 4,500 22.14 WTI Collars ------- 2003 Full Year 10,000 22.00 - 28.91 WTI 2nd Qtr. - 4th Qtr. 6,000 3.70-4.30 Waha Swaps for Purchases ------------------- 2004 8,000 3.91 Socal 2005 8,000 3.85 Socal Subsequent to March 31, 2003, we entered into the following cash flow hedges: Crude Oil Natural Gas ---------------------------------------- ------------------------------------ Bbls / day $ / Bbl Index MMbtu/day $/MMbtu Index ----------- -------------- ------- --------- ---------- --------- Swaps for Sales --------------- 2003 3rd Qtr. 3,500 $ 5.45 Waha 4th Qtr. 4,000 5.50 Waha 2004 1st Qtr 8,500 5.48 Waha& Socal 2nd Qtr. 4,000 4.50 Waha 3rd Qtr. 1,500 $ 24.50 WTI 4,000 4.51 Waha 4th Qtr. 2,000 24.14 WTI 4,000 4.50 Waha 22 ITEM 4. CONTROLS AND PROCEDURES EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES The term "disclosure controls and procedures" is defined in Rule 13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. Our Chief Executive Officer and our Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures as of a date within 90 days before the filing of the quarterly report, and they have concluded that as of that date, our disclosure controls and procedures were effective at ensuring that required information will be disclosed on a timely basis in our reports filed under the Exchange Act. CHANGE IN INTERNAL CONTROLS We maintain a system of internal controls that are designed to provide reasonable assurance that our books and records accurately reflect our transactions and that our established policies and procedures are followed. There were no significant changes to our internal controls or in other factors that could significantly affect our internal controls subsequent to the date of their evaluation by our Chief Executive Officer and our Chief Financial Officer, including any corrective actions with regard to significant deficiencies and material weaknesses. 23 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS See Part I, Item 1, Financial Statements, Note 9, which is incorporated herein by reference. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS None. ITEM 3. DEFAULTS UPON SENIOR SECURITIES None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS None. ITEM 5. OTHER INFORMATION None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (A) EXHIBITS - 99.1 Certification of Chief Executive Officer of Nuevo Energy Company - 99.2 Certification of Chief Financial Officer of Nuevo Energy Company (B) REPORTS ON FORM 8-K: None. 24 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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. NUEVO ENERGY COMPANY (Registrant) Date: May 13, 2003 By: /s/ James L. Payne -------------------- ---------------------------------- James L. Payne Chairman, President and Chief Executive Officer Date: May 13, 2003 By: /s/ Janet F. Clark -------------------- ---------------------------------- Janet F. Clark Senior Vice President and Chief Financial Officer 25 EXHIBIT INDEX Exhibit Number Description ------ ----------- 99.1 Certification of Chief Executive Officer of Nuevo Energy Company 99.2 Certification of Chief Financial Officer of Nuevo Energy Company