-----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, Mf8gnGSziKz/gsY1yf1VxOc+y+BNJQhQB+ZUjL9biBvLlFRGaim9jSIRr6L1u1KU q+G4fshyFSi6rvRfWnZ4ow== 0000899243-02-002312.txt : 20020814 0000899243-02-002312.hdr.sgml : 20020814 20020814145401 ACCESSION NUMBER: 0000899243-02-002312 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20020630 FILED AS OF DATE: 20020814 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: 02735146 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 THE QUARTER ENDING JUNE 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 June 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 small business issuer 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) (713) 821-7100 (Issuer's telephone number) 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 16,624,194 shares as of July 19, 2002 3TEC ENERGY CORPORATION AND SUBSIDIARIES INDEX
PAGE NO. ---- PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Balance Sheets- June 30, 2002 (Unaudited) and December 31, 2001 (Audited) .......... 1 Consolidated Statements of Operations (Unaudited)- Three and six months ended June 30, 2002 and 2001 .................. 2 Consolidated Statements of Cash Flows (Unaudited)- Six months ended June 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 PART II. OTHER INFORMATION Item 4. Submission of Matters to a Vote of Security Holders ............... 15 Item 6. Exhibits and Reports on Form 8-K ................................. 16
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except per share data)
JUNE 30, DECEMBER 31, 2002 2001 ------------- ---------------- (Unaudited) (Audited) ASSETS CURRENT ASSETS Cash and cash equivalents .............................................. $ 3,707 $ 17,762 Accounts receivable .................................................... 13,555 16,835 Income taxes receivable ................................................ 164 4,464 Other current assets ................................................... 2,163 4,473 -------- -------- Total current assets ............................................. 19,589 43,534 PROPERTY AND EQUIPMENT (AT COST) Oil and gas-successful efforts method .................................. 407,450 385,264 Other property and equipment ........................................... 3,833 3,549 -------- -------- 411,283 388,813 Accumulated depreciation, depletion and amortization ........................ (89,751) (71,039) -------- -------- Net Property and Equipment .................................................. 321,532 317,774 OTHER ASSETS ................................................................ 1,333 1,730 -------- -------- TOTAL ASSETS ................................................................ $342,454 $363,038 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable ....................................................... $ 11,676 $ 25,052 Accrued liabilities .................................................... 638 1,322 Series C Preferred stock redemption payable ............................ 1,284 1,349 Derivative fair value liability ........................................ 9,318 -- Other current liabilities .............................................. 939 1,468 -------- -------- Total current liabilities ................................................... 23,855 29,191 LONG-TERM DEBT .............................................................. 99,000 108,000 DEFERRED INCOME TAXES ....................................................... 41,581 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 June 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, 614,776 shares issued and outstanding at June 30, 2002 and December 31, 2001, respectively. $14,755 aggregate liquidation preference ................. 7,485 7,485 Common stock, $.02 par value, 60,000,000 shares authorized, 16,694,001 and 16,547,595 shares issued at June 30, 2002 and December 31, 2001, respectively .................................... 334 331 Additional paid-in capital ............................................. 154,377 151,412 Retained earnings ...................................................... 15,165 18,906 Treasury stock; 69,796 shares at June 30, 2002 and December 31, 2001, respectively .......................................................... (1,049) (1,049) Deferred compensation .................................................. (1,122) -- -------- -------- TOTAL STOCKHOLDERS' EQUITY .................................................. 178,018 180,712 -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .................................. $342,454 $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 SIX MONTHS ENDED JUNE 30, JUNE 30, (Unaudited) (Unaudited) (Unaudited) (Unaudited) 2002 2001 2002 2001 -------------- ------------- ----------- -------------- REVENUES Oil, natural gas and plant income ........... $ 28,171 $ 33,256 $ 46,478 $ 77,775 Gain (loss) on sale of properties ........... (222) 6,749 (145) 6,836 Gain (loss) on derivative fair value ........ 9,011 -- (12,400) -- Gain (loss) on derivatives settlements ...... (4,716) -- 2,168 -- Other ....................................... 12 327 199 452 ----------- ----------- ---------- ----------- TOTAL REVENUES ................................... 32,256 40,332 36,300 85,063 ----------- ----------- ---------- ----------- EXPENSES Production - Lease operations ......................... 3,708 4,786 7,431 9,143 Production, severance and ad valorem taxes 2,255 2,176 3,502 5,165 Gathering, transportation and other ...... 1,066 1,013 2,099 1,828 Geological and geophysical .................. 648 154 828 369 Dry hole and impairments .................... 1,562 -- 1,616 -- Surrendered and expired acreage ............. 589 -- 589 -- General and administrative .................. 2,506 1,807 4,713 3,349 Restricted stock compensation ............... 432 -- 432 -- Interest .................................... 1,019 1,893 2,043 4,074 Depreciation, depletion and amortization .... 9,629 7,007 18,384 13,346 Other ....................................... 191 -- 191 -- ----------- ----------- ---------- ----------- TOTAL EXPENSES ................................... 23,605 18,836 41,828 37,274 INCOME (LOSS) BEFORE INCOME TAX EXPENSE, MINORITY INTEREST AND DIVIDENDS TO PREFERRED STOCKHOLDERS ...................... 8,651 21,496 (5,528) 47,789 Minority Interest ................................ -- 118 -- 301 Income tax (benefit) expense ..................... 3,374 8,168 (2,157) 18,103 ----------- ----------- ---------- ----------- NET INCOME (LOSS) ................................ 5,277 13,210 (3,371) 29,385 Dividends to preferred stockholders .............. 185 184 370 375 ----------- ----------- ---------- ----------- NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS $ 5,092 $ 13,026 $ (3,741) $ 29,010 =========== =========== =========== =========== NET INCOME (LOSS) PER COMMON SHARE BASIC $ 0.31 $ 0.89 $ (0.23) $ 1.99 =========== =========== =========== =========== DILUTED $ 0.27 $ 0.70 $ (0.23) $ 1.56 =========== =========== =========== =========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING BASIC 16,560,905 14,627,066 16,525,827 14,612,342 =========== =========== =========== =========== DILUTED 19,241,113 19,171,852 16,525,827 19,123,258 =========== =========== =========== =========== SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
2 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
SIX MONTHS ENDED JUNE 30 (Unaudited) (Unaudited) 2002 2001 ------------- -------------- OPERATING ACTIVITIES Net income (loss) ................................................................ $ (3,371) $ 29,385 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization .................................... 18,054 12,994 Amortization of debt issue costs ............................................ 330 352 Dry hole and impairments .................................................... 1,616 -- Surrendered and expired acreage ............................................. 589 -- Loss on derivative fair value ............................................... 12,400 -- (Gain) Loss on sale of properties ........................................... 145 (6,836) Deferred income taxes ....................................................... (3,228) 11,159 Restricted stock compensation ............................................... 432 -- Minority interest ........................................................... -- 301 Common stock issued in lieu of directors fees ............................... 13 -- Changes in current assets and liabilities net, of acquisition effects: Accounts receivable and other current assets .............................. 6,875 13,815 Accounts payable, accrued liabilities and other current liabilities ....... (14,842) (1,011) -------- -------- NET CASH PROVIDED BY OPERATING ACTIVITIES ........................................ 19,013 60,159 INVESTING ACTIVITIES Proceeds from sales of properties ........................................... 959 11,654 Acquisition of Classic Resources, Inc., net of cash acquired ................ -- (58,584) Acquisition of oil and gas properties ....................................... -- (4,477) Development of oil and gas properties ....................................... (25,157) (29,675) Additions to other assets ................................................... (287) (755) -------- -------- NET CASH USED IN INVESTING ACTIVITIES ............................................ (24,485) (81,837) FINANCING ACTIVITIES Proceeds from long-term debt ................................................ 18,500 82,000 Principal payments on long-term debt ........................................ (27,500) (56,000) Proceeds from exercise of stock options and warrants ........................ 600 248 Preferred stock dividends ................................................... (183) (188) -------- -------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES .............................. (8,583) 26,060 INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ................................. (14,055) 4,382 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................................. 17,762 4,436 -------- -------- CASH AND CASH EQUIVALENTS AT ENDING OF PERIOD .................................... $ 3,707 $ 8,818 ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for: Interest .................................................................... $ 2,003 $ 3,707 ======== ======== Income taxes ................................................................ $ 963 $ 6,208 ======== ======== Non-cash investing and financing activities: Preferred dividends incurred but not paid ................................... $ 187 $ 186 ======== ======== 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 June 30, 2002 and December 31, 2001, consolidated results of operations and consolidated cash flows for the periods ended June 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 six months ended June 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 three and six month periods ended June 30, 2001:
Three Months Ended Six Months Ended June 30, 2001 June 30, 2001 ------------------ ----------------- Total Revenues ...................... $3,494 $7,839 Costs and operating expenses ........ 961 1,654 Operating income .................... 2,533 6,185 Net Income .......................... 1,571 3,843 Net Income per share (fully diluted). 0.08 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. At June 30, 2002, the Company had a weighted average of 2,623,463 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 six-month periods ended June 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 Six Months Ended June 30, June 30, 2002 2001 2002 2001 ---- ---- ---- ---- Basic net income (loss) attributable to common shareholders ..................................... 5,092 13,026 (3,741) 29,010 Plus preferred stock dividends .................................... 185 184 - 375 Plus interest expense (net of tax) on subordinated convertible notes ............................. - 184 - 365 ------- ------- ------- ------- Fully diluted net income (loss) attributable to common shareholders ..................................... 5,277 13,394 (3,741) 29,750 ======= ======= ======= ======= Basic shares outstanding (weighted average shares) ................ 16,561 14,627 16,526 14,612 Plus potentially dilutive securities: o Dilutive options and warrants applying treasury stock method .................................. 1,932 2,326 - 2,290 o Shares from conversion of subordinated convertible notes ...................................... - 1,466 - 1,468 o Shares from conversion of Series B preferred stock ........................................ 121 131 - 131 o Shares from conversion of Series D preferred stock ........................................ 615 622 - 622 o Non-vested restricted stock .............................. 12 - - ------- ------- ------- ------- Fully diluted shares outstanding (weighted average shares) ........ 19,241 19,172 16,526 19,123 ======= ======= ======= =======
(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 six months ended June 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 Six Months Ended June 30, 2001 (Unaudited) ----------------- Total revenues .................................................. $ 87,133 Net income attributable to common stockholders .................. 26,187 Net income per basic share attributable to common stockholders .. 1.84 5 (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 June 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 June, 30, 2002, the Company has recognized approximately $0.4 million as restricted stock compensation expense and will recognize the remaining $1.2 million over the remaining service and vesting periods of two years. (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 June 30, 2002.
Natural Gas Derivatives - ----------------------- Period Mmbtu Per Day Total Mmbtu Type NYMEX Price ------ ------------- ----------- ---- ----------- July 2002 - October 2002 56,000 6,888,000 Call $3.50 July 2002 - October 2002 28,000 3,444,000 Call $3.15 July 2002 - October 2002 56,000 6,888,000 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 the period from July 1, 2002 to October 30, 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 July 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. During 2002, the Company has paid net cash settlements of approximately $3.6 million related to its derivative activities. The $5.8 million gain from the sale of the put floor and the $3.6 million of net cash paid for settlements on the derivative activities have been included in the statement of operations as gain on derivative settlements. At July 31, 2002 the fair value of the Company's open derivative positions was a $3.0 million mark-to-market loss, with the closed contract months for July and August having settled for total cash payments of $2.3 million. A 10% increase to the July 31 NYMEX prices would result in settlements of the open contract months for the Company's derivatives to increase by $1.2 million while a 10% decrease would result in $2.8 million decrease to these contract settlements. (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 6 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 acretion expense due to the accretion of the associated liability. (8) CREDIT FACILITY During May, 2002, the Company's borrowing base under its Credit Facility was redetermined and increased to $155 million. The increase was effective May 1, 2002. During August, 2002, the Company extended the maturity date of its Credit Facility with its existing bank group until July 2, 2003 under the same terms and conditions. The Company anticipates entering into an extension of the maturity date for the Credit Facility during the third quarter of 2002 which is expected to move the maturity date to August 31, 2004. 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: o financial position; o business strategy; o budgets; o amount, nature and timing of capital expenditures; o drilling of wells; o natural gas and oil reserves; o timing and amount of future production of natural gas and oil; o operating costs and other expenses; o cash flow and anticipated liquidity; o prospect development and property acquisitions; and o marketing of natural gas and oil. Numerous important factors, risks and uncertainties may affect the Company's operating results, including: o the risks associated with exploration; o the ability to find, acquire, market, develop and produce new properties; o natural gas and oil price volatility; o uncertainties in the estimation of proved reserves and in the projection; o future rates of production and timing of development expenditures; o operating hazards attendant to the natural gas and oil business; o downhole drilling and completion risks that are generally not recoverable from third parties or insurance; o potential mechanical failure or under-performance of significant wells; o climactic conditions; o availability and cost of material and equipment; o delays in anticipated start-up dates; o actions or inactions of third-party operators of the Company's properties; o the ability to find and retain skilled personnel; o availability of capital; o the strength and financial resources of competitors; o regulatory developments; o environmental risks; and o 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 at that date 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) pricing parameters at December 31, 2001 $2.57/Mcf and $19.84/Bbl). Historically, we have 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 flows and also affects fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment. 9 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 payment. 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 have budgeted approximately $45-65 million for capital expenditures depending on the price of natural gas and drilling costs in 2002. The low-end of the range is based on an average natural gas price of $2.50/Mmbtu. Pricing increases to $3.00/Mmbtu and above will move the Company's capital expenditures into the higher end of the range. 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 May 31, 2003. On June 30, 2002, the Company's borrowing base under its Credit Facility was set at $155 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 50 basis points or LIBOR plus basis points increasing from a low of 150 to a high of 212.5 as loans outstanding increase as a percentage of the borrowing base. As of June 30, 2002, the borrowing base was set at $155 million. and the Company was paying an average of 3.55% per annum interest on the principal balance of $99 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 June 30, 2002, the amount available to be borrowed under the Credit Facility was approximately $56 million. During August, 2002, the Company extended the maturity date of its Credit Facility with its existing bank group until July 2, 2003 under the same terms and conditions. The Company anticipates entering into an extension of the maturity date for the Credit Facility during the third quarter of 2002 which is expected to move the maturity date to August 31, 2004. 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 June 30, 2002 we were in compliance with the covenants contained in the Credit Facility. 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 11 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 June 30, 2002 will impact our liquidity for the periods covered by these contracts. NYMEX futures prices for natural gas at July 31, 2002 currently exceed our swap and call prices for the period July 2002 to October 2002 and are outside of our collar established for the period November 2002 to March 2003. Cash prices received by the Company for its natural gas production have historically been highly correlated with NYMEX prices. Also, currently the notional call volumes exceed our current actual production volumes and this can be expected to have an additional negative impact to the Company's cash flows and results of operations. Realized NYMEX prices above the call price would have a negative impact on cash flow and results of operations, as the Company will be required to pay the amount the NYMEX price exceeds the swap price and the written call prices. 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. At July 31, the fair value of the Company's open derivative positions was a $3.0 million mark-to-market loss, with the closed contract months for July and August having settled for cash payments of $2.3 million. A 10% increase to the July 31 NYMEX prices would result in settlements of the open contract months for the Company's derivatives to increase by $1.2 million while a 10% decrease would result in a $2.8 million decrease to these contract settlements. 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 Six Months Ended June 30, June 30, --------------------- -------------------- 2002 2001 2002 2001 --------- --------- ------- --------- Net Production Data: Oil and Liquids (MBbls) ............ 212 262 395 577 Natural Gas (MMcf) ................. 6,480 5,617 12,767 10,654 Equivalent Production (MMcfe) ...... 7,752 7,187 15,137 14,117 Average Sales Price: (1) Oil and Liquids (per Bbl) .......... $23.44 $24.99 $21.17 $26.03 Natural Gas (per Mcf) .............. 3.47 4.66 2.89 5.79 Equivalent price (per Mcfe) ........ 3.54 4.55 2.99 5.43 Expenses ($ per Mcfe): Lease operations ................... $0.48 $0.67 $0.49 $0.65 Production, severance and ad valorem 0.29 0.30 0.23 0.37 Gathering, transportation and other. 0.14 0.14 0.14 0.13 General and administrative ......... 0.32 0.25 0.31 0.24 Depreciation and depletion (2) ..... 1.24 0.98 1.21 0.95
(1) Mark-to-market and derivative settlements in 2002 have been excluded. (2) Represents depreciation, depletion and amortization, excluding impairments. Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001 Oil and Gas Revenues. Revenues from oil and gas operations decreased by 15% to $28.2 million for the three months ended June 30, 2002, compared to $33.3 million for the same period during 2001. The decrease is attributable to lower commodity prices received by the Company during the period ($23.44/Bbl and $3.47/Mcf in 12 2002 versus $24.99/Bbl and $4.66/Mcf in 2001), offset somewhat by higher daily production volumes due to recent drilling successes. Gain (loss) on Sale of Properties. The loss on sale of properties for the three months ended June 30, 2002 decreased to $0.2 million compared to a gain of $6.7 million during the same period of 2001. The decrease is a result of the Company's divestment of non-strategic oil and gas properties in 2001 vs. minimal divestiture activity in 2002. Derivatives Fair Value and Settlements. The gain on derivatives fair value of $9.0 million for the three months ended June 30, 2002 represents the fair value mark-to-market adjustment made related to the July 2002 through October 2002 and November 2002 through March 2003 derivative contracts that the Company has in place at June 30, 2002. During the second quarter of 2002, approximately $4.7 million in cash settlements were paid by the Company for derivative contracts that covered the contract period of April 2002 through October 2002. There were no derivative contracts in place at June 30, 2001. Production Expense. Production expense for the three months ended June 30, 2002, decreased by 13% to $7.0 million compared to $8.0 million during the same period of 2001. Lease operating expenses on an $/Mcfe basis decreased to $0.48/Mcfe from $0.67/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 June 30, 2002 increased to $0.6 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 increased in the three months ended June 30, 2002 as a result of the drilling of one exploratory dry hole in the period and the impairment charge recognized as a result of changes in the economics of two minor fields due to an increase in lease operating expenses and a well shut in within one of these two fields. Surrendered and Expired Acreage. The increase in surrendered and expired acreage is attributed to acreage related to the exploratory dry hole which was drilled in the period whereby the Company determined that no further activity would be initiated on the prospect. General and Administrative Expense. General and administrative expense for the three months ended June 30, 2002 increased by $0.7 million compared to the same period in 2001. The increase is attributable to continued increased staffing levels as a result of the Company's significant growth from acquisitions. Restricted Stock Expense. During the three months ended June 30, 2002, the Company recognized restricted stock compensation expense of $0.4 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 June 30, 2002 decreased to $1.0 million compared to $1.9 million for the same period ending June 30, 2001. The decrease is attributable to lower interest rates quarter over quarter (approximately 3.9% in 2002 versus 6.5% in 2001) offset somewhat by slightly higher average debt levels. Depreciation, Depletion and Amortization Expense. DD&A for the three months ended June 30, 2002 was $9.6 million compared to $7.0 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 June 30, 2002, the Company recorded a tax provision of $3.4 million compared to a tax provision of $8.2 million 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%. 13 Dividends to Preferred Stockholders. Dividends to preferred stockholders of approximately $0.2 million in the three months ended June 30, 2002 are comparable to the $0.2 million for the three months ended June 30, 2001. The Company currently has only the Series D dividend to pay which is paid semi-annually on March 31 and September 30. Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001 Oil and Gas Revenues. Revenues from oil and gas operations decreased by 40% to $46.5 million for the six months ended June 30, 2002, compared to $77.8 million for the same period during 2001. The decrease is attributable to lower commodity prices received by the Company during the period ($21.17/Bbl and $2.89/Mcf in 2002 versus $26.03/Bbl and $5.79/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 six months ended June 30, 2002 decreased to $0.1 million compared to a gain of $6.7 million during the same period of 2001. The decrease is a result of the Company's divestment of non-strategic oil and gas properties in 2001 vs. minimal divestiture activity in 2002. Derivatives Fair Value and Settlements. The loss on derivatives fair value of $12.4 million for the six months ended June 30, 2002 represents the fair value mark-to-market adjustment made related to the July 2002 through October 2002 and November 2002 through March 2003 derivative contracts that the Company has in place at June 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 second quarter of 2002, the Company had derivatives settlement payments of approximately 4.7 million. The $5.8 million gain from the sale of the floor and the $3.6 million net monthly settlement payments of the derivative activities have been included in the statement of operations in gain on derivative settlements. There were no derivative contracts in place at June 30, 2001. Production Expense. Production expense for the six months ended June 30, 2002, decreased by 19% to $13.0 million compared to $16.1 million during the same period of 2001. Lease operating expenses on an $/Mcfe basis decreased to $0.49/Mcfe from $0.65/Mcfe, while production, severance and ad valorem taxes decreased to $0.23/Mcfe from $0.37/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 six months ended June 30, 2002 of $2.99/Mcfe vs. $5.43/Mcfe in 2001 is the principal reason for the decrease in taxes. Geological and Geophysical. The increase in Geological and Geophysical expense for the six months ended June 30, 2002 increased to $0.8 million compared to $0.4 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 in the six months ended June 30, 2002 as a result of the drilling of one exploratory dry hole in the period and the impairment charge recognized as a result of changes in the economics of two minor fields due to an increase in lease operating expenses and a well shut in within one of these two fields. Surrendered and Expired Acreage. The increase in surrendered and expired acreage is attributed to acreage related to the exploratory dry hole which was drilled in the period whereby the Company determined that no further activity would be initiated on the prospect. General and Administrative Expense. General and administrative expense for the six months ended June 30, 2002 increased by $1.4 million compared to the same period in 2001. The increase is attributable to continued increased staffing levels as a result of the Company's significant growth from acquisitions. Restricted Stock Expense. During the six months ended June 30, 2002, the Company recognized restricted stock compensation expense of $0.4 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. 14 Interest. Interest expense during the six month period ended June 30, 2002 decreased to $2.0 million compared to $4.1 million for the same period ending June 30, 2001. The decrease is attributable to lower interest rates quarter over quarter (approximately 3.8% in 2002 versus 7.2% in 2001). Depreciation, Depletion and Amortization Expense. DD&A for the six months ended June 30, 2002 was $18.4 million compared to $13.3 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 six months ended June 30, 2002, the Company recorded a tax benefit of $2.2 million compared to a tax provision of $18.1 million during the same period in 2001. The benefit recorded in 2002 represents the Company's net income for the six months ended at its expected effective tax rate for 2002 of approximately 39%. Dividends to Preferred Stockholders. Dividends to preferred stockholders of approximately $0.4 million in the six months ended June 30, 2002 are comparable to the $0.4 million for the six months ended June 30, 2001. The Company currently has only the Series D Dividend to pay 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 June 30, 2002, the Company's variable rate debt had a carrying value of $99 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 June 30, 2002, outstanding natural gas option contracts and swap agreements had a fair value loss of $9.3 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 income statements. At July 31, 2002 the fair value of the Company's open derivative positions was a $3.0 million mark-to-market loss, with the closed contract months for July and August having settled for total cash payments of $2.3 million . A 10% increase to the July 31 NYMEX prices would result in settlements of the open contract months for the Company's derivatives to increase by $1.2 million while a 10% decrease would result in a $2.8 million decrease to these contract settlements. PART II. OTHER INFORMATION ITEMS 1., 2., 3. AND 5. Not Applicable. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The Annual Meeting of Stockholders of the Company was held May 8, 2002, for the purpose of voting on the following items: 1. To elect three (3) class I directors for three-year terms expiring in 2005. 2. The ratification of the appointment of KPMG, LLP as the independent accountants of the Company for the current fiscal year ending December 31, 2002. 15 3. To approve an amendment authorizing the issuance of restricted stock and restatement of the 3TEC Energy Corporation 2001 Stock Option Plan. The following table summarizes the tabulation of votes with respect to the foregoing matters:
For Withheld --------------------------- Proposal 1: Election of three (3) Class I directors for three (3) year terms as follows: Floyd C. Wilson three (3) year 14,886,065 180,049 R.A. Walker three (3) year 14,886,051 180,063 Larry J. Bump three (3) year 14,886,042 180,072 For Against Abstain ---------------------------------------- Proposal 2: Ratification of the appointment of KPMG, LLP 14,868,023 183,819 14,272 as the Company's independent auditors for the fiscal year ending December 31, 2002 Proposal 3: Approval of an amendment authorizing the issuance 7,712,004 5,263,464 19,999 of restricted stock and restatement of the 2001 Stock Option Plan
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.) 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.) 16 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.) 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.) 17 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.) 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.) 18 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). 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 second quarter of 2002: None. 19 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed by the undersigned, thereunto duly authorized, as of August 13, 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 EX-99.1 3 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 June 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 August 13, 2002 EX-99.2 4 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 June 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 August 13, 2002 -----END PRIVACY-ENHANCED MESSAGE-----