-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, UYcimuLZR8dSdPkFtHw//7soCVrr95m2W+BlnEbCUGTOVE1yPqD6FaLBRPUHNoxF /I5kpaemRELyvDtXbiiJww== 0000899243-02-002868.txt : 20021112 0000899243-02-002868.hdr.sgml : 20021111 20021112155143 ACCESSION NUMBER: 0000899243-02-002868 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: 3TEC ENERGY CORP CENTRAL INDEX KEY: 0000903267 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 631081013 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-14745 FILM NUMBER: 02817210 BUSINESS ADDRESS: STREET 1: 700 MILAM STREET STREET 2: SUITE 1100 CITY: HOUSTON STATE: TX ZIP: 77002-2 BUSINESS PHONE: 7138217100 FORMER COMPANY: FORMER CONFORMED NAME: MIDDLE BAY OIL CO INC DATE OF NAME CHANGE: 19930504 10-Q 1 d10q.txt FORM 10-Q FOR QUARTER ENDING SEPTEMBER 30, 2002 U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2002 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to _______ Commission File No. 001-14745 3TEC ENERGY CORPORATION (Exact name of Registrant as specified in its charter) DELAWARE 63-1081013 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 700 MILAM, SUITE 1100 HOUSTON, TX 77002 (Address of principal executive offices, including zip code) (713) 821-7100 (Registrant's telephone number, including area code) N/A (Former Name, Former Address and Former Fiscal Year, If Changed Since Last Report) Indicate by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of 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 [_] Number of shares outstanding of each of the Registrant's classes of common stock, as of the latest practicable date: Common stock, $0.02 par value 16,541,416 shares as of November 8, 2002 3TEC ENERGY CORPORATION AND SUBSIDIARIES INDEX
PAGE NO. ---- PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Balance Sheets- September 30, 2002 (Unaudited) and December 31, 2001 (Audited) ...................... 1 Consolidated Statements of Operations (Unaudited)- Three and nine months ended September 30, 2002 and 2001 ............................. 2 Consolidated Statements of Cash Flows (Unaudited)- Nine months ended September 30, 2002 and 2001 ....................................... 3 Notes to Consolidated Financial Statements (Unaudited) ................................ 4 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations ......................................... 8 Item 3. Quantitative and Qualitative Disclosures About Market Risk ......................... 15 Item 4. Controls and Procedures............................................................. 15 PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K .................................................. 15
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except per share data)
SEPTEMBER 30, DECEMBER 31, 2002 2001 ------------- ------------- (Unaudited) (Audited) ASSETS CURRENT ASSETS Cash and cash equivalents ........................................................ $ 3,952 $ 17,762 Accounts receivable .............................................................. 10,524 16,835 Income taxes receivable .......................................................... 164 4,464 Other current assets ............................................................. 1,575 4,473 --------- --------- Total current assets ....................................................... 16,215 43,534 PROPERTY AND EQUIPMENT (AT COST) Oil and gas-successful efforts method ............................................ 416,632 385,264 Other property and equipment ..................................................... 3,908 3,549 --------- --------- 420,540 388,813 Accumulated depreciation, depletion and amortization .................................. (99,013) (71,039) --------- --------- Net Property and Equipment ............................................................ 321,527 317,774 OTHER ASSETS, net ..................................................................... 1,160 1,730 --------- --------- TOTAL ASSETS .......................................................................... $ 338,902 $ 363,038 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable ................................................................. $ 9,341 $ 25,052 Accrued liabilities .............................................................. 582 1,322 Series C Preferred stock redemption payable ...................................... 1,274 1,349 Derivative fair value liability .................................................. 6,233 -- Other current liabilities ........................................................ 1,163 1,468 --------- --------- Total current liabilities ............................................................. 18,593 29,191 LONG-TERM DEBT ........................................................................ 97,000 108,000 DEFERRED INCOME TAXES ................................................................. 42,716 45,135 STOCKHOLDERS' EQUITY Preferred stock, $0.02 par, 20,000,000 shares authorized, 266,667 designated Series B, 2,300,000 shares designated Series C and 725,167 shares designated Series D, none other designated ........................ -- -- Convertible preferred stock Series B, $7.50 stated value, 207,905 and 266,667 shares issued and outstanding at September 30, 2002 and December 31, 2001, respectfully. $1,559 aggregate liquidation preference ..... 2,828 3,627 Convertible preferred stock Series D, 5% $24.00 stated value, 613,919 and 614,776 shares issued and outstanding at September 30, 2002 and December 31, 2001, respectively. $14,734 aggregate liquidation preference ........................... 7,475 7,485 Common stock, $.02 par value, 60,000,000 shares authorized, 16,695,932 and 16,547,595 shares issued at September 30, 2002 and December 31, 2001, respectively .............................................. 334 331 Additional paid-in capital ....................................................... 154,866 151,412 Retained earnings ................................................................ 17,261 18,906 Treasury stock; 69,796 shares at September 30, 2002 and December 31, 2001, respectively ..................................................................... (1,049) (1,049) Deferred Compensation ............................................................ (1,122) -- TOTAL STOCKHOLDERS' EQUITY ............................................................ 180,593 180,712 --------- --------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ............................................ $ 338,902 $ 363,038 ========= =========
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 1 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, (Unaudited) (Unaudited) (Unaudited) (Unaudited) 2002 2001 2002 2001 -------------- ------------- ----------- -------------- REVENUES Oil, natural gas and plant income ................. $ 25,256 $ 20,802 $ 70,842 $ 97,690 Gain (loss) on sale of properties ................. 70 (3,417) (74) 3,419 Gain (loss) on derivative fair value .............. 3,086 -- (9,314) -- Loss on derivative settlements .................... (4,099) -- (1,931) -- Other ............................................. 10 145 210 597 -------------- ------------- ----------- -------------- TOTAL REVENUES ......................................... 24,323 17,530 59,733 101,706 -------------- ------------- ----------- -------------- EXPENSES Production - Lease operations ............................... 3,750 3,758 10,732 12,412 Production, severance and ad valorem taxes ..... 2,052 1,364 5,555 6,529 Gathering, transportation and other ............ 758 777 2,415 2,206 Geological and geophysical ........................ 257 176 1,085 545 Dry hole and impairments .......................... 1,069 1,667 2,685 1,667 Surrendered and expired acreage ................... 160 -- 749 -- General and administrative ........................ 2,216 1,810 6,928 5,159 Restricted stock compensation ..................... 288 -- 720 -- Interest .......................................... 1,000 1,545 3,043 5,619 Depreciation, depletion and amortization .......... 8,853 7,199 27,237 20,544 Other ............................................. 188 -- 380 -- -------------- ------------- ----------- -------------- TOTAL EXPENSES ......................................... 20,591 18,296 61,529 54,681 INCOME (LOSS) BEFORE INCOME TAX EXPENSE, MINORITY INTEREST AND DIVIDENDS TO PREFERRED STOCKHOLDERS ............................ 3,732 (766) (1,796) 47,025 Minority interest ...................................... -- 148 -- 448 Income tax (benefit) expense ........................... 1,455 2 (702) 18,105 -------------- ------------- ------------ -------------- NET INCOME (LOSS) ...................................... 2,277 (916) (1,094) 28,472 Dividends to preferred stockholders .................... 181 187 551 562 -------------- ------------- ----------- -------------- NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS .................................. $ 2,096 $ (1,103) $ (1,645) $ 27,910 ============== ============= ============ ============== NET INCOME (LOSS) PER COMMON SHARE BASIC ............................................. $ 0.13 $ 0.07 $ (0.10) $ 1.89 ============== ============= ============ ============== DILUTED ........................................... $ 0.12 $ 0.07 $ (0.10) $ 1.52 ============== ============= ============ ============== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING BASIC ............................................. 16,541 15,135 16,537 14,791 ============== ============= =========== ============== DILUTED ........................................... 18,892 15,135 16,537 19,072 ============== ============= =========== ==============
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 2 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
NINE MONTHS ENDED SEPTEMBER 30 (Unaudited) (Unaudited) 2002 2001 ------------- ------------ OPERATING ACTIVITIES Net income (loss) ................................................................. $ (1,094) $ 28,472 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ..................................... 26,742 20,001 Amortization of debt issue costs ............................................. 495 543 Dry hole and impairments ..................................................... 2,685 1,667 Surrendered and expired acreage .............................................. 749 - Loss on derivative fair value ................................................ 9,314 - (Gain) Loss on sale of properties ............................................ 74 (3,419) Deferred income taxes ........................................................ (1,913) 10,815 Restricted stock compensation ................................................ 720 - Minority interest ............................................................ - 448 Common stock issued in lieu of directors fees ................................ 21 - Other ........................................................................ 155 ------------- ------------ Cash Flow from Operations before changes in current assets and liabilities ........ 37,793 58,682 Changes in current assets and liabilities, net of acquisition effects: Accounts receivable and other current assets ............................... 10,504 14,835 Accounts payable, accrued liabilities and other current liabilities ........ (16,837) 6,979 ------------- ------------ NET CASH PROVIDED BY OPERATING ACTIVITIES ......................................... 31,460 80,496 INVESTING ACTIVITIES Proceeds from sales of properties ............................................ 1,082 38,081 Acquisition of Classic Resources, Inc., net of cash acquired ................. - (58,670) Acquisition of oil and gas properties ........................................ - (18,511) Development of oil and gas properties ........................................ (35,045) (56,646) Additions to other assets .................................................... (366) (1,978) ------------- ------------- NET CASH USED IN INVESTING ACTIVITIES ............................................. (34,329) (97,724) FINANCING ACTIVITIES Proceeds from long-term debt ................................................. 24,500 104,000 Principal payments on long-term debt ......................................... (35,500) (72,000) Proceeds from exercise of stock options and warrants ......................... 610 522 Preferred stock dividends .................................................... (551) (188) ------------- ------------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES ............................... (10,941) 32,334 INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .................................. (13,810) 15,106 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD .................................. 17,762 4,436 ------------- ------------ CASH AND CASH EQUIVALENTS AT ENDING OF PERIOD ..................................... $ 3,952 $ 19,542 ============= ============ SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for: Interest ..................................................................... $ 3,025 $ 5,615 ============= ============ Income taxes ................................................................. $ 963 $ 10,554 ============= ============ Non-cash investing and financing activities: Preferred dividends incurred but not paid .................................... $ -- $ 374 ============= ============ Deferred taxes recorded in acquisition of Classic ............................ $ 325 $ 27,566 ============= ============
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 3 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (1) BASIS OF PRESENTATION In management's opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting primarily of normal recurring adjustments) necessary to present fairly the consolidated financial position of the Company as of September 30, 2002 and December 31, 2001, consolidated results of operations and consolidated cash flows for the periods ended September 30, 2002 and 2001. These consolidated financial statements should be read in conjunction with the Company's financial statements and notes thereto included in the Company's Annual Report on Form 10-KSB for the year ended December 31, 2001. The results of operations for the nine months ended September 30, 2002, are not necessarily indicative of the results which may be expected for any other interim period or for the entire fiscal year ending December 31, 2002. The Company restated its financial results for the first two quarters of 2001. The changes reflected adjustments to oil and natural gas production and revenues as a result of the Company's over accrual of revenue related to these quarters. The impact of the adjustments decreased the previously reported amounts as follows for the nine month period ended September 30, 2001: Nine Months Ended September 30, 2001 ------------------ Total Revenues $ 7,839 Costs and operating expenses 1,654 Operating income 6,185 Net Income 3,843 Net Income per share (fully diluted) 0.20 (2) RECLASSIFICATIONS Certain reclassifications of prior period amounts have been made to conform to the current presentation. (3) EARNINGS PER SHARE Basic earnings and loss per common share are based on the weighted average shares outstanding without any dilutive effects considered. Diluted earnings and loss per share reflect dilution from all potential common shares, including options, warrants and convertible preferred stock and convertible notes. Diluted loss per share does not include the effect of any potential common shares if the effect would be anti-dilutive. For the nine month period ending September 30, 2002, the Company had a weighted average of 2,534,394 stock options, warrants and convertible preferred stock outstanding which were not included in the computation of diluted earnings per share, because the effect of the assumed exercise of these stock options, warrants and convertible securities would have an antidilutive effect on the computation of diluted loss per share. Basic and diluted earnings per share for the three and nine-month periods ended September 30, 2002 and 2001 was determined as follows (in thousands): 4 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, 2002 2001 2002 2001 ---- ---- ---- ---- Basic net income (loss) attributable to common shareholders ...................................... 2,096 (1,103) (1,645) 27,910 Plus preferred stock dividends .................................... 181 187 551 562 Plus interest expense (net of tax) on subordinated convertible notes .............................. - 310 - 494 --------- ---------- --------- ---------- Fully diluted net income (loss) attributable to common shareholders ...................................... 2,277 (606) (1,094) 28,966 ========= ========== ========= ========== Basic shares outstanding (weighted average shares) ................ 16,541 15,135 16,537 14,791 Plus potentially dilutive securities: . Dilutive options and warrants applying treasury stock method .................................. 1,595 - - 2,215 . Shares from conversion of subordinated convertible notes ...................................... - - - 1,314 . Shares from conversion of Series B preferred stock ........................................ 120 - - 131 . Shares from conversion of Series D preferred stock ........................................ 614 - - 621 . Non-vested restricted stock .............................. 22 - - - --------- ---------- --------- ---------- Fully diluted shares outstanding (weighted average shares) ........ 18,892 15,135 16,537 19,072 ========= ========== ========= ==========
(4) ACQUISITIONS On January 30, 2001, the Company acquired 100% of the issued and outstanding stock of Classic Resources Inc. (the "Classic Acquisition") for cash consideration of approximately $53.5 million plus other acquisition costs. The operating results of the Classic Acquisition have been included in the consolidated financial statements since that date. Classic was a privately held exploration and production company with properties located in East Texas. The Company's estimate of total net proved reserves at the time of the acquisition was 47 Bcfe and net daily production of approximately 11 Mmcfe, as of January 31, 2001. The Classic Acquisition was financed under the Company's existing Credit Facility. The purchase price of the Classic Acquisition was allocated principally to proved properties, with additional amounts allocated to working capital related to amounts recorded for production related receivables and payables in existence and accrued for at January 31, 2001. In connection with the Classic Acquisition, approximately $29 million in deferred income taxes were recorded as a result of the difference between the allocated purchase price and the historical tax basis of the properties. The following pro forma data presents the results of the Company for the nine months ended September 30, 2001, as if the Classic Acquisition had occurred on January 1, 2001. The pro forma data assumes the acquisition of the respective properties and the debt financing transactions related to these acquisitions. The pro forma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisitions been consummated as presented. (in thousands, except per share amounts):
Pro Forma Nine Months Ended September 30, 2001 (Unaudited) ------------------ Total revenues ........................................................... $ 105,129 Net income attributable to common stockholders ........................... 25,739 Net income per basic share attributable to common stockholders ........... 1.74
5 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) (Unaudited) (5) STOCKHOLDERS' EQUITY During March, 2002, a holder of the Company's Series B Preferred Stock ("Series B") elected to convert 58,762 Series B shares into 34,065 shares of the Company's Common Stock ("Common"). The conversion ratio was determined using the convertible shares at December 31, 2001 whereby 266,667 Series B shares were convertible into 154,591 shares of Common. At September 30, 2002, 207,905 Series B shares were outstanding. During May 2002, the Company issued 95,000 shares of restricted stock to certain members of the Company's management valued at $1.6 million. At September 30, 2002, the Company has recognized approximately $0.7 million as restricted stock compensation expense and will recognize the remaining $0.9 million over the remaining service and vesting periods of two years. Of the 95,000 shares that were issued, 10,832 shares have vested and are outstanding as of September 30, 2002. The remaining shares will vest over a two-year period or when the Company's stock price meets a certain price target, as defined by the plan documents. (6) DERIVATIVE ACTIVITIES During February 2002, the Company unwound the floor portion of the April through October 2002 collar for net proceeds of approximately $5.8 million ($0.48/Mmbtu), and then re-swapped the 56,000 Mmbtu of daily natural gas production at $2.56/Mmbtu. Also during February 2002, the Company put in place a collar on 20,000 Mmbtu of daily gas production from November 2002 to March 2003 with a floor of $3.20/Mmbtu and a weighted average ceiling of $3.53/Mmbtu. The following table details the Company's derivative contract positions which were in place at September 30, 2002.
Natural Gas Derivatives - ----------------------- Period Mmbtu Per Day Total Mmbtu Type NYMEX Price ------ ------------- ----------- ---- ----------- October 2002 56,000 1,736,000 Call $3.50 October 2002 28,000 868,000 Call $3.15 October 2002 56,000 1,736,000 Swap $2.56 November 2002 - March 2003 20,000 3,020,000 Put $3.20 November 2002 - March 2003 10,000 1,510,000 Call $3.40 November 2002 - March 2003 20,000 3,020,000 Call $3.60
For October 2002 the Company has notional volumes of 84,000 Mmbtu per day under written call derivatives in addition to 56,000 Mmbtu related to the swap contract in place for the same period. These notional volumes exceed actual production volumes at October 1, 2002 of approximately 70,000 MCF per day. To the extent that the actual NYMEX price exceeds the written call strike prices of $3.15/MCF and $3.50/MCF there would be an additional negative impact to the Company's cash flow and results of operations. Through September 30, 2002, the Company has paid net cash settlements of approximately $7.7 million related to its derivative activities. The $5.8 million gain from the sale of the put floor and the $7.7 million of net cash paid for settlements on the derivative activities have been included in the statement of operations as loss on derivative settlements. At October 31, 2002 the fair value of the Company's open derivative positions was a $3.1 million mark-to-market loss, with the closed contract months for October and November having settled for total cash payments of $3.1 million. A 10% increase to the October 31 NYMEX prices would result in settlements of the open contract months (December 2002 through March 2003) for the Company's derivatives to increase by $0.7 million while a 10% decrease would result in a $2.3 million decrease to these contract settlements versus the October 31, 2002 mark-to-market loss. 6 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued) (Unaudited) (7) ACCOUNTING PRONOUNCEMENTS In October, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. While SFAS 144 supersedes SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long Lived Assets to Be Disposed Of, it retains many of the fundamental provisions of that Statement. SFAS 144 also supersedes the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of business. However, it retains the requirement in Opinion 30 to report separately discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. By broadening the presentation of discontinued operations to include more disposal transactions, the FASB has enhanced management's ability to provide information that helps financial statement users to assess the effects of a disposal transaction on the ongoing operations of an entity. Statement No. 144 is effective for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. The Company adopted SFAS 144 effective January 1, 2002. The Company expects that adoption of SFAS 144 will result in increased disclosure of material oil and gas property sales as discontinued operations. In August, 2001, the FASB issued SFAS 143, Accounting for Asset Retirement Obligations. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) normal use of the asset. SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. Implementation of SFAS 143 is required for fiscal year 2003. To accomplish this, the Company must identify all legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations on the date of adoption. The determination of fair value is complex and will require the Company to gather market information and develop cash flow models. Additionally, the Company will be required to develop processes to track and monitor these obligations. Due to the effort necessary to comply with the adoption of SFAS 143, it is not practicable for management to estimate precisely the impact of adopting SFAS 143 at the date of this report but adoption is likely to increase the Company's oil and gas assets, liabilities, depreciation, depletion, and amortization ("DD&A) (hereafter defined) expense and accretion expense due to the accretion of the associated liability. During second quarter 2002 the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, and requires that all gains and losses from extinguishment of debt should be classified as extraordinary items only if they meet the criteria in APB No. 30. Applying APB No. 30 will distinguish transactions that are part of an entity's recurring operations from those that are unusual or infrequent or that meet the criteria for classification as an extraordinary item. Any gain or loss on extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB No. 30 for classification as an extraordinary item must be reclassified. The Company does not expect that there will be any current impact from SFAS No. 145. The FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, in June 2002. This statement 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 applies to costs incurred in an "exit activity," which includes, but is not limited to, a restructuring, or a "disposal activity" covered by SFAS No. 144. SFAS No. 146 will be effective for the Company in January 2003. The Company does not believe there is any current impact of SFAS No. 146. (8) CREDIT FACILITY During September, 2002, the Company amended its credit agreement to increase its borrowing base to $160 million and extend its maturity date to August 31, 2004. This change was effective September 30, 2002. 7 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Cautionary Statement About Forward-Looking Statements Some of the information in this Quarterly Report on Form 10-Q, including information incorporated by reference, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities and Exchange Act of 1934. The forward-looking statements speak only as of the date made and the Company undertakes no obligation to update such forward-looking statements. These forward-looking statements may be identified by the use of the words "believe," "expect," "anticipate," "will," "contemplate," "would" and similar expressions that contemplate future events. These future events include the following matters: . financial position; . business strategy; . budgets; . amount, nature and timing of capital expenditures; . drilling of wells; . natural gas and oil reserves; . timing and amount of future production of natural gas and oil; . operating costs and other expenses; . cash flow and anticipated liquidity; . prospect development and property acquisitions; and . marketing of natural gas and oil. Numerous important factors, risks and uncertainties may affect the Company's operating results, including: . the risks associated with exploration; . the ability to find, acquire, market, develop and produce new properties; . natural gas and oil price volatility; . uncertainties in the estimation of proved reserves and in the projection; . future rates of production and timing of development expenditures; . operating hazards attendant to the natural gas and oil business; . downhole drilling and completion risks that are generally not recoverable from third parties or insurance; . potential mechanical failure or under-performance of significant wells; . climactic conditions; . availability and cost of material and equipment; . delays in anticipated start-up dates; . actions or inactions of third-party operators of the Company's properties; . the ability to find and retain skilled personnel; . availability of capital; . the strength and financial resources of competitors; . regulatory developments; . environmental risks; and . general economic conditions. Any of the factors listed above and other factors contained in this Form 10-Q could cause the Company's actual results to differ materially from the results implied by these or any other forward-looking statements made by the Company or on its behalf. The Company cannot assure you that future results will meet its expectations. 8 OVERVIEW We are engaged in the acquisition, development, production and exploration of oil and natural gas reserves. Our properties are concentrated in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. Our management and technical staff have substantial experience in each of these areas. As of December 31, 2001, we had estimated total net proved reserves of 263 Bcfe, of which approximately 88% were natural gas and approximately 77% were proved developed, with an estimated PV-10 value of $212 million (using Securities and Exchange Commission pricing parameters at December 31, 2001 ($2.57/Mcf and $19.84/Bbl)). As of September 30, 2002, we had estimated total net proved reserves of 298 Bcfe, of which approximately 86% were natural gas and approximately 80% were proved developed, with an estimated PV-10 value of $436 million (using Securities and Exchange Commission pricing parameters at September 30, 2002 ($4.08/Mcf and $30.45/Bbl)). Prior to 2002, we have historically increased our reserves and production principally through acquisitions. We focus on properties that have a substantial proved reserve component and which management believes to have additional exploitation opportunities. Recently, we have also acquired a number of drilling prospects covered by an extensive 3-D seismic database that we believe have exploration potential. We have assembled an experienced management team and technical staff with expertise in property acquisitions and development, reservoir engineering, exploration and financial management. DESCRIPTION OF CRITICAL ACCOUNTING POLICIES Oil and Natural Gas Properties. We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method, all development and acquisition costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves or proved reserves, as applicable. Exploration expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Expenditures for repairs and maintenance to sustain or increase production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different or additional proven or unproven reservoir are capitalized pending determination that economic reserves have been added. If the recompletion to an unproven reservoir is not successful, the expenditures are charged to expense. Expenditures for redrilling or directional drilling in a previously abandoned well are classified as drilling costs to a proven or unproven reservoir for determination of capital or expense. Significant tangible equipment added or replaced is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reserves are capitalized. Internal costs directly associated with the development and exploitation of properties are capitalized as a cost of the property and are classified accordingly in the Company's financial statements. Crude oil volumes are converted to equivalent Mcfe's at the rate of one barrel to six Mcfe. The Company is required to assess the need for an impairment of capitalized costs of oil and natural gas properties and other long-lived assets whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. Any impairment charge incurred is recorded in accumulated depletion, depreciation, and amortization ("DD&A") to reduce our recorded basis in the asset. Each part of this calculation is subject to a large degree of management judgment, including the determination of a property's reserves, future cash flows, and fair value. Management's assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, reducing our net income and our basis in the related asset. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. There can be no assurance that the proved reserves will be developed within the periods estimated or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, as well as the property's fair value. Additionally, as management's views related to future prices change, this changes the calculation of future net cash 9 flows and also affects fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment. DD&A expense is also directly affected by the Company's reserve estimates. Any change in reserves directly impacts the amount of DD&A expense the Company recognizes in a given period. Assuming no other changes, such as an increase in depreciable base, as the Company's reserves increase the amount of DD&A expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves. The Company also uses estimates to record its accrual for oil and natural gas revenues. The volume portion of the accrual of revenue for a given period is based upon field production reports (both operated and non-operated), estimates of production added via drilling or acquisitions, historical production averages and natural production declines of the Company's properties. The price component of the Company's accrual for revenue incorporates historical averages of the Company's sales as compared to the monthly closing NYMEX price for natural gas and the West Texas Intermediate index price for crude oil. Several factors can impact the Company's ability to estimate its production volume such as the fact that a significant portion of the Company's production is operated by third parties. Reliance on accurate and timely data from the operators of these properties can change the actual amounts of production for which the Company receives payments. Additionally, production meters that are manually read can be different than the volume metered at the Company's sales points. Both the Company's estimate of sold volumes and the estimate of the price received for these sales is adjusted on an on-going basis as the Company receives payment for the accrued volumes. Changes in the estimates of the accrual are adjusted for in the subsequent periods as payment is received or additional supporting data is obtained. Bad Debt Expense. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. The Company historically has not required collateral or other performance guarantees from creditworthy counterparties. Many of our receivables are from joint interest owners on property of which we are the operator. Thus, we may have the ability to withhold future revenue disbursements to cover any non-payment of joint interest billings. Our oil and natural gas receivables typically turnover quickly, usually one month for oil and two months for gas; thus, signaling any problem accounts in a timely manner. Counterparties to our derivative commodity contracts are routinely reviewed for creditworthiness to determine the realizability of any related derivative assets we might carry on our books. This review of receivables and counterparties is heavily dependent on the judgment of management. If it is determined that the carrying value of a receivable or financial instrument might not be recoverable, we record an allowance to the extent we believe the receivable or asset is not recoverable. The determination as to what extent a receivable or asset might be impaired is also heavily dependent on the judgment of management. As more information becomes known related to a particular counterparty or customer, management will continually reassess previous judgments and any resulting change in the related allowance could have a material positive or negative effect on our financial position and results of operations in the period of the change. Derivative Activities. We use various financial instruments in the normal course of our business to manage and reduce price volatility and other market risks associated with our crude oil and natural gas production. This activity is referred to as risk management. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is generally accomplished through over-the-counter forward derivative contracts executed with large financial institutions. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities". This standard requires us to recognize all of our derivative and hedging instruments in our consolidated balance sheets as either assets or liabilities and measure them at fair value. If a derivative does not qualify for hedge accounting, it must be adjusted to fair value through earnings. However, if a derivative does qualify for hedge accounting, depending on the nature of the hedge, changes in fair value can be offset against the change in fair value of the hedged item through earnings or recognized in other comprehensive income until such time as the hedged item is recognized in earnings. 10 To qualify for cash flow hedge accounting, the cash flows from the hedging instrument must be highly effective in offsetting changes in cash flows due to changes in the underlying items being hedged. In addition, all hedging relationships must be designated, documented, and reassessed periodically. The Company's natural gas derivative financial instruments were not designated as hedges at the time the instruments were executed and, as such, these instruments are marked-to-market through earnings each period. LIQUIDITY AND CAPITAL RESOURCES We believe that our cash flows from operations are adequate to meet the requirements of operating our business. However, future cash flows are subject to a number of variables, including our level of production and prices, and we cannot assure that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Our principal operating sources of cash include sales of natural gas and oil production. For the year 2002, we expect to spend $55-60 million for capital expenditures. We are obligated to pay dividends of approximately $740,000 per year on the Series D Preferred Stock which we may pay in either cash or in additional shares of Series D Preferred Stock during the three years ending February 1, 2003. Our activities in 2002 have been financed through operating cash flow and bank borrowings. Our primary source of financing for acquisitions has been borrowing under our Credit Facility described below. Credit Facility. The Company has in place a $250 million credit facility (the "Credit Facility") with Bank One, NA as agent and seven other banks. The Credit Facility, as amended, matures August 31, 2004. On September 30, 2002, the Company's borrowing base under its Credit Facility was set at $160 million. The borrowing base is to be redetermined semi-annually on May 1 and November 1 and provides for interest as revised under the Credit Facility to accrue at a rate calculated at the Company's option as either the bank's prime rate plus a low of zero to a high of 37.5 basis points or LIBOR plus basis points increasing from a low of 150 to a high of 200 as loans outstanding increase as a percentage of the borrowing base. As of September 30, 2002, the Company was paying an average of 3.36% per annum interest on the principal balance of $97 million under the Credit Facility. Prior to maturity, no payments of principal are required so long as the borrowing base exceeds the loan balance. The borrowings under the Credit Facility are secured by substantially all of the Company's oil and natural gas properties. At September 30, 2002, the amount available to be borrowed under the Credit Facility was approximately $63 million. During September 2002, the Company extended the maturity date of its Credit Facility with its existing bank group until August 31, 2004 under conditions discussed in the preceding paragraph. In connection with the Credit Facility we are required to adhere to certain affirmative and negative covenants. The loan agreement contains a number of dividend restrictions and restrictive covenants which, among other things, require the maintenance of minimum current and interest coverage ratios. As of September 30, 2002 we were in compliance with the covenants contained in the Credit Facility and expect to be in compliance for the remainder of 2002. Market Risk. We generally sell our oil at local field prices paid by the principal purchasers of oil. The majority of our natural gas production is sold at spot prices. Accordingly, we are generally subject to the commodity prices for these resources as they vary from time to time. Inflation and Changes in Prices. Our revenues and the value of our oil and gas properties have been and will be affected by changes in natural gas and crude oil prices. Our ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on natural gas and crude oil prices. These prices are subject to significant seasonal and other fluctuations that are beyond our ability to control or predict. Costs and expenses are affected by the level of inflation. Should current conditions in the industry be sustained, increased competition resulting in a relative shortage of oilfield supplies and/or services, inflationary cost pressures may continue. Derivative Activities. Our derivative contracts in effect at September 30, 2002 will impact our liquidity for the periods covered by these contracts. The Company anticipates that the cash flow from its physical production will provide sufficient liquidity to settle any obligation generated by the monthly settlement terms of the Company's derivative contract activities. Since September 30, 2002, the contract months for October and November have settled for cash payments of $3.1 million. NYMEX futures prices for natural gas at October 31, 2002 11 are above our collar established for the period December 2002 to March 2003. Cash prices received by the Company for its natural gas production have historically been highly correlated with NYMEX prices. At October 31, 2002, the fair value of the Company's open derivative positions was a $3.1 million mark-to-market loss. A 10% increase to the October 31 NYMEX prices would result in settlements of the open contract months (December 2002 through March 2003) for the Company's derivatives to increase by $0.7 million while a 10% decrease would result in a $2.3 million decrease to these contract settlements versus the October 31, 2002 mark-to-market loss. You should read the following discussion and analysis together with our audited consolidated financial statements and the related notes for the fiscal year ended December 31, 2001, filed in our 2001 Form 10-KSB. Our revenue, profitability, and future rate of growth are dependent upon prevailing prices for oil and gas, which, in turn, depend upon numerous factors such as economic, political, and regulatory developments as well as competition from other sources of energy. The energy markets historically have been highly volatile, and future decreases in prices could have an adverse effect on our financial position, results of operations, quantities of reserves that may be economically produced, and access to capital. The following table reflects certain summary operating data for the periods presented:
Three Months Ended Nine Months Ended September 30, September 30, -------------------- ------------------ 2002 2001 2002 2001 --------- --------- ------- --------- Net Production Data : Oil and Liquids (MBbls) .............................................. 185 206 580 784 Natural Gas (MMcf) ................................................... 6,480 5,662 19,246 16,316 Equivalent Production (MMcfe) ........................................ 7,592 6,898 22,728 21,020 Average Sales Price: (1) Oil and Liquids (per Bbl) ............................................ $ 24.55 $ 23.09 $22.25 $ 25.25 Natural Gas (per Mcf) ................................................ 3.18 2.81 2.99 4.76 Equivalent price (per Mcfe) .......................................... 3.31 3.00 3.10 4.64 Expenses ($ per Mcfe): Lease operations ..................................................... $ 0.49 $ 0.54 0.47 $ 0.59 Production, severance and ad valorem ................................. 0.27 0.20 0.24 0.31 Gathering, transportation and other .................................. 0.10 0.11 0.11 0.10 General and administrative ........................................... 0.29 0.26 0.30 0.25 Depreciation and depletion (2) ....................................... 1.17 1.04 1.20 0.98
(1) Mark-to-market and derivative settlements in 2002 have been excluded. (2) Represents depreciation, depletion and amortization, excluding impairments. Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001 Oil and Gas Revenues. Revenues from oil and gas operations increased by 22% to $25.3 million for the three months ended September 30, 2002, compared to $20.8 million for the same period during 2001. The increase is attributable to higher commodity prices received by the Company during the period ($24.55/Bbl and $3.18/Mcf in 2002 versus $23.09/Bbl and $2.81/Mcf in 2001), as well as higher daily production volumes due to recent drilling successes. 12 Gain (loss) on Sale of Properties. Property sales for the three months ended September 30, 2002 resulted in a gain of $0.1 million compared to a loss of $3.4 million during the same period of 2001. The variance is a result of the Company's divestment of non-strategic oil and gas properties in 2001 versus minimal divestiture activity in 2002. Derivatives Fair Value and Settlements. The gain on derivatives fair value of $3.1 million for the three months ended September 30, 2002 represents the fair value mark-to-market adjustment made related to the Company's open positions at June 30, 2002 versus the open positions at September 30, 2002. During the third quarter of 2002, approximately $4.1 million in cash settlements were paid by the Company for derivative contracts that covered the contract period of July 2002 through September 2002. There were no derivative contracts in place at September 30, 2001. Production Expense. Production expense for the three months ended September 30, 2002, increased by 12% to $6.6 million compared to $5.9 million during the same period of 2001. Lease operating expenses on an $/Mcfe basis decreased to $0.49/Mcfe from $0.54/Mcfe. Lower per unit operating costs associated with the Company's acquired properties and higher per unit operating costs of properties sold by the Company during the 2nd and 3rd quarters of 2001 are attributed to the current period decreases. Geological and Geophysical. Geological and Geophysical expense for the three months ended September 30, 2002 increased to $0.3 million compared to $0.2 million in 2001. The increase is attributed primarily to the Company's exploratory activities and related costs incurred for acquisition and reprocessing of seismic data. Dry Hole and Impairments. Dry hole and impairments decreased to $1.1 million compared to $1.7 million in 2001. The expense for the three months ended September 30, 2002 is attributable to plug and abandon costs on one particular well as well as an impairment charge on a well where reserves have declined as a result of reservoir and production problems. The expense for the same period in 2001 resulted from the drilling of a dry hole. Surrendered and Expired Acreage. The increase in surrendered and expired acreage is attributed to geological and geophysical costs associated with exploratory activities. General and Administrative Expense. General and administrative expense for the three months ended September 30, 2002 increased by $0.4 million compared to the same period in 2001. The increase is attributable to continued increases in staffing levels as a result of the Company's significant growth. Restricted Stock Expense. During the three months ended September 30, 2002, the Company recognized restricted stock compensation expense of $0.3 million which is attributed to the share grants made to certain officers of the Company that were approved at the Company's annual meeting in May, 2002. Interest. Interest expense during the three-month period ended September 30, 2002 decreased to $1.0 million compared to $1.5 million for the same period ending September 30, 2001. The decrease is attributable to lower interest rates quarter over quarter (approximately 3.8% in 2002 versus 5.6% in 2001) offset somewhat by slightly higher average debt levels. Depreciation, Depletion and Amortization Expense. DD&A for the three months ended September 30, 2002 was $8.9 million compared to $7.2 million for the same period of 2001. The increase in DD&A recorded is attributed to the Company's production growth and the impact of its developmental drilling activities whereby the Company converts proved undeveloped reserves into proved developed producing reserves. Income Taxes. For the three months ended September 30, 2002, the Company recorded a tax provision of $1.5 million compared to a tax provision of $2 thousand during the same period in 2001. The provision recorded in 2002 represents the Company's net income for the three months ended at its expected effective tax rate for 2002 of approximately 39%. Dividends to Preferred Stockholders. Dividends to preferred stockholders of approximately $0.2 million in the three months ended September 30, 2002 are comparable to the $0.2 million for the three months ended September 30, 2001. The Company currently has only the Series D dividend to pay which is paid semi-annually on March 31 and September 30. 13 Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001 Oil and Gas Revenues. Revenues from oil and gas operations decreased by 28% to $70.8 million for the nine months ended September 30, 2002, compared to $97.7 million for the same period during 2001. The decrease is attributable to lower commodity prices received by the Company during the period ($22.25/Bbl and $2.99/Mcf in 2002 versus $225.25/Bbl and $4.76/Mcf in 2001), partially offset by higher daily production volumes due to recent drilling successes. Gain (loss) on Sale of Properties. The loss on sale of properties for the nine months ended September 30, 2002 amounted to $0.1 million compared to a gain of $3.4 million during the same period of 2001. The variance is a result of the Company's divestment of non-strategic oil and gas properties in 2001 versus minimal divestiture activity in 2002. Derivatives Fair Value and Settlements. The loss on derivatives fair value of $9.3 million for the nine months ended September 30, 2002 represents the fair value mark-to-market adjustment made related to the Company's open positions at December 31, 2001 versus the open positions at September 30, 2002. During the first quarter of 2002 the Company unwound the floor portion of the April 2002 through October 2002 contract for a gain of approximately $5.8 million. Additionally, approximately $1.1 million in cash settlements were received by the Company for a derivative contract that covered the contract period of November 2001 through March 2002, which expired during the first quarter of 2002. During the third quarter of 2002, the Company had derivatives settlement payments of approximately $4.1 million. There were no derivative contracts in place at September 30, 2001. Production Expense. Production expense for the nine months ended September 30, 2002, decreased by 11% to $18.7 million compared to $21.1 million during the same period of 2001. Lease operating expenses on an $/Mcfe basis decreased to $0.47/Mcfe from $0.59/Mcfe, while production, severance and ad valorem taxes decreased to $0.24/Mcfe from $0.31/Mcfe. Lower per unit operating costs associated with the Company's acquired properties and higher per unit operating costs of properties sold by the Company during the 2nd and 3rd quarters of 2001 are attributed to the current period decreases. Lower realized commodity prices during the nine months ended September 30, 2002 of $3.10/Mcfe vs. $4.64/Mcfe in 2001 is the principal reason for the decrease in taxes. Geological and Geophysical. Geological and geophysical expense for the nine months ended September 30, 2002 increased to $1.1 million compared to $0.5 million in 2001. The increase is attributed primarily to the Company's exploratory activities and related costs incurred for acquisition and reprocessing of seismic data. Dry Hole and Impairments. Dry hole and impairments increased by $1.0 million in the nine months ended September 30, 2002 as a result of plugging and abandoning a well during the period and an impairment charge recognized on a well where reserves have declined as a result of reservoir and production problems. Surrendered and Expired Acreage. The increase in surrendered and expired acreage is attributed to geological and geophysical costs associated with exploratory activities. General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2002 increased by $1.8 million compared to the same period in 2001. The increase is attributable to continued increases in staffing levels as a result of the Company's significant growth. Restricted Stock Expense. During the nine months ended September 30, 2002, the Company recognized restricted stock compensation expense of $0.7 million which is attributed to the share grants made to certain officers of the Company that were approved at the Company's annual meeting in May, 2002. Interest. Interest expense during the nine-month period ended September 30, 2002 decreased to $3.0 million compared to $5.6 million for the same period ending September 30, 2001. The decrease is attributable to lower interest rates quarter over quarter (approximately 3.8% in 2002 versus 6.6% in 2001). Depreciation, Depletion and Amortization Expense. DD&A for the nine months ended September 30, 2002 was $27.2 million compared to $20.5 million for the same period of 2001. The increase in DD&A recorded is attributed to the Company's production growth and the impact of its developmental drilling activities whereby the Company converts proved undeveloped reserves into proved developed producing reserves. 14 Income Taxes. For the nine months ended September 30, 2002, the Company recorded a tax benefit of $0.7 million compared to a tax provision of $18.1 million during the same period in 2001. The benefit recorded in 2002 reflects the Company's net loss at the expected effective tax rate for 2002 of approximately 39%. Dividends to Preferred Stockholders. Dividends to preferred stockholders of approximately $0.6 million in the nine months ended September 30, 2002 are comparable to the $0.6 million for the nine months ended September 30, 2001. The Company currently pays only the Series D Dividend, which is paid semi-annually on March 31 and September 30. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in the Company's 2001 Annual Report on Form-10KSB, as well as with the consolidated financial statements and notes thereto included in this quarterly report on Form 10-Q. Interest Rate Risk The Company is exposed to interest rate risk on short-term and long-term debt carrying variable interest rates. At September 30, 2002, the Company's variable rate debt had a carrying value of $97 million, which approximated its fair value. Commodity Price Risk The Company manages through the use of derivative contracts a portion of the market risks associated with its natural gas sales. As of September 30, 2002, outstanding natural gas option contracts and swap agreements had a fair value loss of $6.2 million. Because these natural gas option contracts and swap agreements were not designated hedge derivatives, changes in their fair value is recognized in the consolidated operating statements. At October 31, 2002, the fair value of the Company's open derivative positions was a $3.1 million mark-to-market loss, with the closed contract months for October and November having settled for cash payments of $3.1 million. A 10% increase to the October 31 NYMEX prices would result in settlements of the open contract months (December 2002 through March 2003) for the Company's derivatives to increase by $0.7 million while a 10% decrease would result in a $2.3 million decrease to these contract settlements versus the October 31, 2002, mark-to-market loss. ITEM 4. CONTROLS AND PROCEDURES Within 90 days of the filing of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the Company's disclosure controls and procedures (as defined in Rule 13a-14(c) of the Securities and Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company's disclosure controls and procedures are effective. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weakness. PART II. OTHER INFORMATION ITEMS 1., 2., 3., 4. AND 5. Not Applicable. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: The following documents are filed as exhibits to this report: 2.1 Agreement and Plan of Merger, dated December 21, 1999, by and between 3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration, LLC and ECIC Corporation, EnCap Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., and Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit C to Form DEF14A, filed January 11, 2000.) 2.2 Agreement and Plan of Merger, dated November 24, 1999, by and between 3TEC Energy Corporation, a Delaware corporation, and Middle Bay Oil Company, Inc., an Alabama corporation. (Incorporated by reference to Exhibit A to Form DEF14A, filed October 25, 1999.) 15 2.3 First Amendment to Agreement and Plan of Merger, effective as of January 14, 2000, by and among 3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration, LLC, ECIC Corporation, EnCap Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., and Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit 2.1 to Form 8-K filed February 4, 2000.) 2.4 Second Amendment to Agreement and Plan of Merger, effective as of February 2, 2000, by and among 3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration, LLC, ECIC Corporation, EnCap Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., and Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit 2.2 to Form 8-K filed February 4, 2000.) 2.5 Form of Agreement of Sale and Purchase by and between C.W. Resources, Inc., Westerman Royalty, Inc., and Carl A. Westerman and 3TEC Energy Corporation. (Incorporated by Reference to Exhibit 10.32 to Form S-2 filed April 28, 2000.) 2.6 Form of Stock Purchase Agreement by and between 3TEC Energy Corporation and Classic Resources, Inc., Natural Gas Partners IV, L.P., Natural Gas Partners V, L.P., and certain individual signatories. (Incorporated by reference to Exhibit 2.1 to Form 8-K filed February 13, 2001.) 2.7 Merger Agreement, dated October 25, 2001, by and among 3TEC Energy Corporation, 3NEX Acquisition Corporation and Enex Resources Corporation. (Incorporated by reference to Exhibit 2.7 to Form 10-KSB filed April 1, 2002.) 2.8 Certificate of Ownership and Merger Merging Enex Resources Corporation into 3TEC Energy Corporation filed with the Delaware Secretary of State January 31, 2002. (Incorporated by reference to Exhibit 2.8 to Form 10-KSB filed April 1, 2002.) 3.1 Certificate of Incorporation of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.1 of Form 8-K filed December 6, 1999.) 3.2 Certificate of Amendment to the Certificate of Incorporation of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.3 of Form 10-KSB filed March 30, 2000.) 3.3 Certificate of Amendment of the Certificate of Incorporation of 3TEC Energy Corporation, dated June 14, 2001 (Incorporated by reference to Exhibit 3.5 Form 10-QSB filed August 8, 2001.) 3.4 Certificate of Merger of Middle Bay Oil Company, Inc. into 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.3 of Form 8-K/A filed December 16, 1999.) 3.5 Bylaws of the Company. (Incorporated by reference to Exhibit C to Form DEF14A filed October 25, 1999.) 3.6 Amendment No. 1 to Bylaws of the Company. (Incorporated by reference to Exhibit 4.5 Form S-8 filed October 26, 2001.) 3.7 Amendment No. 2 to Bylaws of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.6 to Form 10-QSB filed August 8, 2001.) 4.1 Certificate of Designation of Series B Preferred Stock of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.1 to Form 8-K/A filed December 16, 1999.) 4.2 Certificate of Designation of Series D Preferred Stock of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 4.3 to Form 10-QSB filed May 15, 2000.) 10.1 Securities Purchase Agreement, dated July 1, 1999 by and between the Company and 3TEC Energy Corporation. (Incorporated by reference to Exhibit C Form DEF14A filed July 19, 1999.) 10.2 Securities Purchase Agreement, dated August 27, 1999 by and between the Company and Shoemaker Family Partners, LP. (Incorporated by reference to Exhibit 10.2 to Form 10-QSB filed November 15, 1999.) 10.3 Securities Purchase Agreement, dated August 27, 1999 by and between the Company and Shoeinvest II, LP. (Incorporated by reference to Exhibit 10.3 to Form 10-QSB filed November 15, 1999.) 10.4 Securities Purchase Agreement, dated October 19, 1999 between The Prudential Insurance Company of America and the Company. (Incorporated by reference to Exhibit 10.1 to Form 8-K filed November 2, 1999.) 16 10.5 Shareholders Agreement, dated August 27, 1999 by and among the Company, 3TEC Energy Corporation and the Major Shareholders. (Incorporated by reference to Exhibit 10.5 to Form 10-QSB filed November 15, 1999.) 10.6 Agreement to Terminate Shareholders' Agreement, dated April 30, 2001, by and among the Company and the Major Shareholders. (Incorporated by reference to Exhibit 10.6 to Form 10-QSB filed November 8, 2001.) 10.7 Registration Rights Agreement, dated August 27, 1999 by and among the Company, 3TEC Energy Corporation, the Major Shareholders, Shoemaker Family Partners, LP and Shoeinvest II, LP. (Incorporated by reference to Exhibit 10.6 to Form 10-QSB filed November 15, 1999.) 10.8 Amendment to Registration Rights Agreement, dated October 19, 1999 by and among the Company, W/E Energy Company, L.L.C. f/k/a 3TEC Energy Company L.L.C., f/k/a 3TEC Energy Corporation, Shoemaker Family Partners, LP, Shoeinvest II, LP, and The Prudential Insurance Company of America. (Incorporated by reference to Exhibit 10.2 to Form 8-K filed November 2, 1999.) 10.9 Participation Rights Agreement, dated October 19, 1999 by and among the Company, The Prudential Insurance Company of America and W/E Energy Company L.L.C. (Incorporated by reference to Exhibit 10.3 to Form 8-K filed November 2, 1999.) 10.10 Employment Agreement, dated April 15, 2000 by and between Floyd C. Wilson and the Company. (Incorporated by reference to Exhibit 10.9 to Form S-2 filed April 28, 2000.) 10.11 Employment Agreement, dated May 1, 2000, by and between R.A. Walker and the Company. (Incorporated by reference to Exhibit 10.9 to Form S-2 filed April 28, 2000.) 10.12 Restated Credit Agreement by and among Middle Bay Oil Company, Inc., Enex Resources Corporation and Middle Bay Production Company, Inc. as borrowers, and Bank One, Texas, N.A. and other institutions as lenders. (Incorporated by reference to Exhibit 10.1 to Form 8-K/A filed December 17, 1999.) 10.13 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest II, LP, Compass Bank, and Bank of Oklahoma, National Association. (Incorporated by reference to Exhibit 10.16 to Form 10-QSB filed November 15, 1999.) 10.14 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest II, LP, Compass Bank, and Bank of Oklahoma, National Association. (Incorporated by reference to Exhibit 10.16 to Form 10-QSB filed November 15, 1999.) 10.15 Letter Amendment No. 1 to Middle Bay Oil Company, Inc. Securities Purchase Agreement, dated November 23, 1999, by and between Middle Bay Oil Company, Inc. (n/k/a 3TEC Energy Corporation) and The Prudential Insurance Company of America (Incorporated by reference to Exhibit 10.21 to Form S-2 filed April 28, 2000 and replacing the unexecuted Exhibit 10.17 of Form 10-QSB filed November 15, 1999.) 10.16 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc., Bank One Texas, N.A. and 3TEC Energy Company L.L.C. (Incorporated by reference to Exhibit 10.18 to Form S-2 filed April 28, 2000.) 10.17 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc., Bank One Texas, N.A. and Shoemaker Family Partners, LP. (Incorporated by reference to Exhibit 10.19 to Form S-2 filed April 28, 2000.) 10.18 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc., Bank One Texas, N.A. and Shoeinvest II, LP. (Incorporated by reference to Exhibit 10.20 to Form S-2 filed April 28, 2000.) 10.19 Amendment to Securities Purchase Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc. and 3TEC Energy Company L.L.C. (Incorporated by reference to Exhibit 10.22 to Form S-2 filed April 28, 2000.) 17 10.20 Amendment to Securities Purchase Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc. and Shoemaker Family Partners, LP. (Incorporated by reference to Exhibit 10.23 to Form S-2 filed April 28, 2000.) 10.21 Amendment to Securities Purchase Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc. and Shoeinvest II, LP. (Incorporated by reference to Exhibit 10.24 to Form S-2 filed April 28, 2000.) 10.22 Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan. (Incorporated by reference to Exhibit B to Form DEF 14A filed May 5, 1997.) 10.23 Amendment No. 1 to the Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan. (Incorporated by reference to Exhibit B to Form DEF 14A filed May 5, 1998.) 10.24 Amendment No. 1 to Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan. (Incorporated by reference to Exhibit 99.7 Form S-8 filed November 6, 2000.) 10.25 Amendment No. 3 to Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan. (Incorporated by reference to Exhibit 99.8 Form S-8 filed November 6, 2000.) 10.26 1999 Stock Option Plan. (Incorporated by reference to Exhibit E to Form DEF 14A filed October 25, 1999.) 10.27 Amendment No. 1 to 3TEC Energy Corporation 1999 Stock Option Plan. (Incorporated by reference to Exhibit 99.4 Form S-8 filed November 6, 2000.) 10.28 2000 Stock Option Plan (Incorporated by reference to Exhibit A to Form DEF 14A filed on May 1, 2000.) 10.29 Amendment No. 1 to 3TEC Energy Corporation 2000 Stock Option Plan. (Incorporated by reference to Exhibit 99.2 Form S-8 filed November 6, 2000.) 10.30 3TEC Energy Corporation 2001 Stock Option Plan. (Incorporated by reference to Exhibit 99.1 Form S-8 filed October 26, 2001.) 10.31 3TEC Energy Corporation 2000 Non-Employee Directors Stock Option Plan. (Incorporated by reference to Exhibit 99.2 Form S-8 filed October 26, 2001.) 10.32 Amendment No. 1 to 3TEC Energy Corporation 2000 Non-Employee Directors' Stock Option Plan. (Incorporated by reference to Exhibit 10.32 to Form 10-Q filed May 13, 2002). 10.33 Second Restated Credit Agreement among 3TEC Energy Corporation, Enex Resources Corporation, Middle Bay Production Company, Inc., and Magellan Exploration, LLC, as Borrowers, and Bank One, Texas, N.A. and the Institutions named therein, as Lenders, Bank One, Texas, N.A., as Administrative Agent, Bank of Montreal as Syndication Agent and Banc One Capital Markets, Inc., as Arranger, dated May 31, 2000. (Incorporated by reference to Exhibit 10.28 to Form S-2/A filed June 6, 2000.) 10.34 First Amendment to Shareholders' Agreement by and among 3TEC Energy Corporation, the W/E Shareholders and the Major Shareholders, dated May 30, 2000. (Incorporated by reference to Exhibit 10.29 to Form S-2/A filed June 6, 2000.) 10.35 Third Restated Credit Agreement among 3TEC Energy Corporation, Enex Resources Corporation and 3TEC/CRI Corporation, as Borrowers, and Bank One, N.A. and the Institutions named therein, as Lenders, Bank One, N.A., as Administrative Agent, Bank of Montreal as Syndication Agent and Banc One Capital Markets, Inc., as Arranger, dated March 12, 2001. (Incorporated by reference to Exhibit 10.27 to Form 10-QSB filed May 14, 2001.) 10.36 3TEC Energy Corporation Amended and Restated 2001 Stock Option and Restricted Stock Plan (Incorporated by reference to Exhibit B to Form DEF 14A filed April 4, 2002). 18 10.37 Letter Amendment to Third Restated Credit Agreement among 3TEC Energy Corporation, as Borrower, and Bank One, N.A., as Administrative Agent and Lender, and the Major Lenders, dated September 30, 2002.* 99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* 99.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.* * Filed herewith (b) The following reports were filed on Form 8-K during the third quarter of 2002: None. 19 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, as of November 12, 2002. 3TEC ENERGY CORPORATION (Registrant) By: /s/ Floyd C. Wilson ----------------------------------------- Floyd C. Wilson Chairman and Chief Executive Officer By: /s/ R.A. Walker ----------------------------------------- R.A. Walker President, Chief Financial Officer, Director By: /s/ Shane M. Bayless ----------------------------------------- Shane M. Bayless Vice President-Controller, Treasurer and Principal Accounting Officer 20 CERTIFICATIONS I, Floyd C. Wilson, certify that: 1. I have reviewed this quarterly report on Form 10-Q of 3TEC Energy Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 12, 2002 By: /s/ Floyd C. Wilson Floyd C. Wilson Chief Executive Officer 21 I, R.A. Walker, certify that: 1. I have reviewed this quarterly report on Form 10-Q of 3TEC Energy Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 12, 2002 By: /s/ R.A. Walker R.A. Walker Chief Financial Officer 22 EX-10.37 3 dex1037.txt CREDIT AGREEMENT LETTER EXHIBIT 10.37 September 18, 2002 3TEC Energy Corporation 700 Milam Street, Suite 1100 Houston, Texas 77002-8215 Attention: Shane Bayless, Vice President-Accounting Re: Third Restated Credit Agreement among 3TEC Energy Corporation ("3TEC") and Bank One, NA et al. (the "Credit Agreement") Gentlemen: You have requested an amendment to the Credit Agreement to extend the Maturity Date thereof, amend the procedure for determining the Borrowing Base, increase the Borrowing Base, change the Base Rate Margin and LIBOR Margins and change the asset sales basket. Specifically, the Credit Agreement is amended in the following respects: (a) Section 1 of the Credit Agreement is hereby amended in the following respects: (i) The definition of "Base Rate Margin" is hereby deleted and the following new definition substituted in lieu thereof: "Base Rate Margin shall be: (i) three-eighths of one percent (.375%) per annum whenever the Borrowing Base Usage is equal to or greater than 90%; or (ii) one-quarter of one percent (.25%) per annum whenever the Borrowing Base Usage is equal to or greater than 66% but less than 90%; or (iii) zero percent (0%) per annum whenever the Borrowing Base Usage is less than 66%." (ii) The definition of "LIBOR Margin" is hereby deleted and the following new definition substituted in lieu thereof: "LIBOR Margin shall be: (i) two percent (2%) per annum whenever the Borrowing Base Usage is equal to or greater than 90%; (ii) one and three-quarters percent (1.75%) per annum whenever the Borrowing Base Usage is equal to or greater than 66%, but less than 90%; (iii) one and one-half percent (1.50%) per annum whenever the Borrowing Base Usage is less than 66%." (iii) The definition of "Maturity Date" is hereby deleted and the following new definition and substituted in lieu thereof: "Maturity Date shall mean August 31, 2004." (b) Section 7(b) of the Credit Agreement is hereby amended by deleting therefrom in its entirety the fifth sentence from the end of said Section 7(b) and substituting the following new sentence in lieu thereof: "The redetermined Borrowing Base shall be then determined based upon the weighted arithmetic average of the proposed amount submitted by each Lender, excluding the highest and lowest Borrowing Base determined among the individual Lenders." (c) Section 13(a) is hereby amended by deleting Subsection (ii) therefrom in its entirety and substituting the following in lieu thereof: "(ii) sell, lease, transfer or otherwise dispose of, in any fiscal year, any of their assets except for (A) sales, leases, transfers or other dispositions made in the ordinary course of Borrowers' oil and gas businesses, (B) sales, leases or transfers or other dispositions made by Borrowers between Borrowing Base Determination Dates which do not exceed an aggregate of ten percent (10%) of the then current Borrowing Base in net proceeds, and (C) other sales, leases, transfer or other dispositions made with the consent of Majority Lenders which are made pursuant to, and in full compliance with, Section 12(r) hereof;" As of the date of this letter amendment, the Borrowing Base shall be $160,000,000 until redetermined pursuant to the provisions of Section 7(b) of the Credit Agreement. The Lenders hereby confirm that they have received notice that ENEX Resources Corporation merged into 3TEC Energy Corporation effective January 31, 2002, and 3TEC/CRI Corporation merged into 3TEC Energy Corporation effective August 8, 2002. Accordingly, the term "Borrowers" as used herein and in the Credit Agreement shall hereafter mean only 3TEC Energy Corporation. Except to the extent that its provisions are specifically amended, modified or superseded by this and by prior amendments thereto, the representations, warranties and affirmative and negative covenants of the Borrowers contained in the Credit Agreement are incorporated herein by reference for all purposes as if copied herein in full. The Borrowers hereby restate and reaffirm each and every term and provision of the Credit Agreement, as amended, (except to the extent such terms and provisions relate solely to an earlier date), including, without limitation, all representations, warranties and affirmative and negative covenants. If the foregoing meets with your approval, please execute this letter at the place indicated below and return an executed copy to the Agent. This Amendment shall not be effective until it is executed by the Borrowers and by Majority Lenders (as defined in the Credit Agreement). Very truly yours, BANK ONE, NA Administrative Agent (Main Office Chicago) By: /s/ Ronald L. Dierker Ronald L. Dierker RLD/jat Director,Capital Markets APPROVED THIS 30th DAY OF SEPTEMBER, 2002 BORROWERS: 3TEC ENERGY CORPORATION a Delaware corporation By: /s/ Shane M. Bayless Name: Shane M. Bayless Title: VP - Controller & Treasurer LENDERS: BANK ONE, NA (Main Office Chicago) as Administrative Agent and as a Lender By: /s/ Ronald L. Dierker Ronald L. Dierker Director, Capital Markets THE BANK OF NOVA SCOTIA By: /s/ M.D. Smith Name: M.D. Smith Title: Agent UNION BANK OF CALIFORNIA, N.A. By: /s/ Carl Stutzman Name: Carl Stutzman Title: Senior Vice President and Manager By: /s/ Dustin Gaspari Name: Dustin Gaspari Title: Vice President BMO NESBITT BURNS FINANCING, INC. as Syndication Agent and a Lender By: /s/ Cahal B. Carmody Name: Cahal B. Carmody Title: Vice President WELLS FARGO BANK TEXAS, NATIONAL ASSOCIATION By: /s/ Jeff Dalton Name: Jeff Dalton CIBC, INC. By: /s/ Nora Q. Catiis Name: Nora Q. Catiis Title: Authorized Signatory COMERICA BANK-TEXAS By: /s/ Daniel G. Steele Name: Daniel G. Steele Title: Sr. Vice President FLEET NATIONAL BANK By: /s/ Daniel S. Schockling Name: Daniel S. Schockling Title: Director EX-99.1 4 dex991.txt CERTIFICATION OF CEO EXHIBIT 99.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the accompanying Quarterly Report of 3TEC Energy Company (the "Company") on Form 10-Q for the period ending September 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Floyd C. Wilson, Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,to the best of my knowledge and belief that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Floyd C. Wilson Chief Executive Officer November 12, 2002 EX-99.2 5 dex992.txt CERTIFICATION OF CFO EXHIBIT 99.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the accompanying Quarterly Report of 3TEC Energy Company (the "Company") on Form 10-Q for the period ending September 30, 2002 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, R.A. Walker, Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002,to the best of my knowledge and belief that: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ R.A. Walker Chief Financial Officer November 12, 2002 -----END PRIVACY-ENHANCED MESSAGE-----