-----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, S5QEGHhUq2SR8GVWwiyaby6rxC9HNfd0RuuqTozcIliyDktBfu6VHKa9eZlM0vn0 1UPnnANHzPWRYW08Rmgp5A== 0000867665-02-000018.txt : 20021114 0000867665-02-000018.hdr.sgml : 20021114 20021114123617 ACCESSION NUMBER: 0000867665-02-000018 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP CENTRAL INDEX KEY: 0000867665 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 742584033 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-16071 FILM NUMBER: 02823257 BUSINESS ADDRESS: STREET 1: 500 N LOOP 1604 E STE 100 CITY: SAN ANTONIO STATE: TX ZIP: 78232 BUSINESS PHONE: 2104904788 MAIL ADDRESS: STREET 1: 500 N LOOP 1604 EAST STE 100 CITY: SAN ANTONIO STATE: TX ZIP: 78232 10-Q 1 abpq3.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended September 30, 2002 ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-19118 ABRAXAS PETROLEUM CORPORATION ---------------------------------------------------------------------- (Exact name of Registrant as specified in its charter) Nevada 74-2584033 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization Identification Number) 500 N. Loop 1604, East, Suite 100, San Antonio, Texas 78232 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code (210) 490-4788 Not Applicable (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the restraint was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X or No __ The number of shares of the issuer's common stock outstanding as of November 14, 2002 was: Class Shares Outstanding Common Stock, $.01 Par Value 29,979,397 1 of 42 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES FORM 10 - Q INDEX PART I FINANCIAL INFORMATION ITEM 1 - Financial Statements (Unaudited) Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.....................................3 Consolidated Statements of Operations - Three and Nine Months Ended September 30, 2002 and 2001...5 Consolidated Statement of Stockholders'Equity (Deficit) Nine months ended September 30, 2002......................6 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001.............7 Notes to Consolidated Financial Statements.........................8 ITEM 2 - Managements Discussion and Analysis of Financial Condition and Results of Operations....................................24 ITEM 3 - Quantitative and Qualitative Disclosure about Market Risks........37 ITEM 4 - Controls and Procedures...........................................39 PART II OTHER INFORMATION ITEM 1 - Legal proceedings 39 ITEM 2 - Changes in Securities................................................39 ITEM 3 - Defaults Upon Senior Securities......................................39 ITEM 4 - Submission of Matters to a Vote of Security Holders..................39 ITEM 5 - Other Information................................................... 39 ITEM 6 - Exhibits and Reports on Form 8-K.....................................39 Signatures ...................................................40 2
Abraxas Petroleum Corporation and Subsidiaries Part 1- Financial Information Item 1 - Financial Statements Consolidated Balance Sheets (Unaudited) September 30, December 31, 2002 2001 ------------- ------------ (In Thousands) Assets: Current assets: Cash ............................................................. $ 13,358 $ 7,605 Accounts receivable, less allowances for doubtful accounts: Joint owners .............................................. 1,700 2,785 Oil and gas production .................................... 4,367 4,758 Other ..................................................... 1,424 504 -------- -------- 7,491 8,047 Equipment inventory ............................................... 1,061 1,251 Other current assets .............................................. 672 443 -------- -------- Total current assets ............................................ 22,582 17,346 Property and equipment: Oil and gas properties, full cost method of accounting: Proved ........................................................ 516,084 486,098 Unproved, not subject to amortization ......................... 6,704 10,626 Other property and equipment ..................................... 42,557 67,632 -------- -------- Total .................................................... 565,345 564,356 Less accumulated depreciation, depletion, and amortization ................................................ 415,815 282,462 -------- -------- Total property and equipment - net ............................ 149,530 281,894 Deferred financing fees, net of accumulated amortization of $9,951 and $8,668 at September 30, 2002 and December 31, 2001, respectively 2,952 3,928 Deferred income taxes ............................................... 8,442 -- Other assets ........................................................ 387 448 -------- -------- Total assets ...................................................... $183,893 $303,616 ======== ========
See accompanying notes to consolidated financial statements 3
Abraxas Petroleum Corporation and Subsidiaries Part 1- Financial Information Item 1 - Financial Statements Consolidated Balance Sheets (continued) (Unaudited) September 30, December 31, 2002 2001 ------------- ----------- (In Thousands) Liabilities and Stockholders' Equity (Deficit) Current liabilities: Accounts payable ................................................. $ 8,484 $ 10,542 Oil and gas production payable ................................... 2,696 3,596 Accrued interest ................................................. 9,422 6,013 Other accrued expenses ........................................... 1,993 1,116 Hedge liability .................................................. 644 658 Current maturities of long-term debt ............................. 63,500 415 --------- --------- Total current liabilities .............................. 86,739 22,340 Long-term debt ..................................................... 231,199 285,184 Deferred income taxes .............................................. -- 20,621 Future site restoration ............................................ 3,987 4,056 Stockholders' equity (deficit): Common Stock, par value $.01 per share- Authorized 200,000,000 shares; issued, 30,145,280 at September 30, 2002 and December 31, 2001 ........................ 301 301 Additional paid-in capital ...................................... 136,830 136,830 Accumulated deficit .............................................. (263,921) (151,094) Receivables from stock sales ..................................... (97) (97) Treasury stock, at cost, 165,883 shares .......................... (964) (964) Accumulated other comprehensive loss ............................. (10,181) (13,561) --------- --------- Total stockholders' deficit .................................. (138,032) (28,585) --------- --------- Total liabilities and stockholders' equity (deficit)................ $ 183,893 $ 303,616 ========= =========
See accompanying notes to consolidated financial statements 4
Abraxas Petroleum Corporation and Subsidiaries Consolidated Statements of Operations (Unaudited) Three Months Ended Nine Months Ended September 30, September 30, 2002 2001 2002 2001 ------------- ----------- ----------- ---------- (In thousands except per share data) Revenue: Oil and gas production revenues .................... $ 10,129 $ 13,667 $ 34,158 $ 62,043 Gas processing revenues ............................ 522 777 1,933 1,711 Rig revenues ....................................... 169 199 513 607 Other .............................................. 241 258 499 742 --------- --------- --------- --------- 11,061 14,901 37,103 65,103 Operating costs and expenses: Lease operating and production taxes ............... 3,943 4,488 11,205 13,679 Depreciation, depletion, and amortization .......... 5,086 8,021 21,010 25,150 Proved property impairment ......................... -- -- 115,995 -- Rig operations ..................................... 143 204 439 548 General and administrative ......................... 1,399 1,367 4,578 5,051 General and administrative (Stock-based compensation) .................................... -- (1,366) -- (2,767) --------- --------- --------- --------- 10,571 12,714 153,227 41,661 --------- --------- --------- --------- Operating income (loss) ............................... 490 2,187 (116,124) 23,442 Other (income) expense: Interest income .................................... (15) (46) (56) (74) Amortization of deferred financing fees ............ 425 405 1,283 1,315 Interest expense ................................... 8,616 8,090 25,790 23,700 Other expense ...................................... -- -- -- 16 --------- --------- --------- --------- 9,026 8,449 27,017 24,957 --------- --------- --------- --------- Net loss from operations before taxes ................. (8,536) (6,262) (143,141) (1,515) Income tax expense (benefit) .......................... (98) (608) (30,314) 3,677 Minority interest in income of consolidated foreign subsidiary ......................................... -- 195 -- 1,676 --------- --------- --------- --------- Net loss .............................................. $ (8,438) $ (5,849) $(112,827) $ (6,868) ========= ========= ========= ========= Loss per common share: Net loss per common share - basic and diluted ..... $ (0.28) $ (0.22) $ (3.76) $ (0.28) ========= ========= ========= =========
See accompanying notes to consolidated financial statements 5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) (Unaudited) (In thousands except share amounts) Accumulated Receiv- Other ables Common Stock Treasury Stock Additional Accumu- Compre- from ------------------- ---------------- Paid-In lated hensive Stock Shares Amount Shares Amount Capital Deficit Income(Loss) Sale Total ----------- ------- ------- -------- ----------- ---------- ------------- -------- ---------- Balance at December 31, 2001............. 30,145,280 $ 301 165,883 $ (964) $136,830 $(151,094) $(13,561) $(97) $ (28,585) Comprehensive income (loss) - Note 10 Net loss............................... - - - - - (112,827) - - (112,827) Other comprehensive income: Hedge loss........................... - - - - - - 54 54 Foreign currency translation adjustment......................... - - - - - - 3,326 - 3,326 ---------- Comprehensive income (loss)....... - - - - - - - - (109,447) ---------- ----- -------- ------- -------- ---------- --------- ------- ---------- Balance at September 30, 2002........... 30,145,280 $ 301 165,883 $ (964) $136,830 $(263,921) $(10,181) $(97) $(138,032) ========== ===== ======== ======= ======== ========== ========= ======= ==========
See accompanying notes to consolidated financial statements 6
Abraxas Petroleum Corporation and Subsidiaries Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, ------------------------ 2002 2001 ----------- ---------- (In thousands) Operating Activities Net loss ......................................................... $(112,827) $ (6,868) Adjustments to reconcile net loss to net cash provided by operating activities: Minority interest in income of foreign subsidiary ................ -- 1,676 Depreciation, depletion, and amortization ........................ 21,010 25,150 Proved property impairment ....................................... 115,995 -- Deferred income tax (benefit) expense ............................ (30,314) 2,957 Amortization of deferred financing fees .......................... 1,283 1,315 Amortization of debt discount .................................... 287 -- Stock-based compensation ......................................... -- (2,767) Changes in operating assets and liabilities: Accounts receivable .......................................... 499 13,598 Equipment inventory .......................................... 191 (234) Other ........................................................ (249) -- Accounts payable and accrued expenses ........................ 1,305 (8,738) --------- --------- Net cash provided by (used in) operating activities ............... (2,820) 26,089 --------- --------- Investing Activities Capital expenditures, including purchases and development of properties ................................................... (33,392) (44,793) Proceeds from sale of oil and gas producing properties............. 33,678 15,361 Acquisition of minority interest .................................. -- (2,248) --------- --------- Net cash provided by (used in) investing activities ............... $ 286 $ (31,680) --------- --------- Financing Activities Proceeds from long-term borrowings ..................................... 17,084 12,866 Payments on long-term borrowings ....................................... (8,176) (8,873) Deferred financing fees ................................................ (303) -- Exercise of stock options .............................................. -- 16 Other .................................................................. -- 231 --------- --------- Net cash provided by financing activities .............................. 8,605 4,240 --------- --------- Effect of exchange rate changes on cash ................................ (318) (161) --------- --------- Increase (decrease) in cash ............................................ 5,753 (1,512) Cash, at beginning of period ........................................... 7,605 2,004 --------- --------- Cash, at end of period ................................................. $ 13,358 $ 492 ========= ========= Supplemental disclosures of cash flow information: Interest paid .......................................................... $ 22,336 $ 20,262 ========= ========= Taxes paid ............................................................. $ -- $ 505 ========= =========
See accompanying notes to consolidated financial statements 7 Abraxas Petroleum Corporation and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) September 30, 2002 Note 1. Basis of Presentation The accounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the Company's audited consolidated financial statements in the Annual Report on Form 10-K filed for the year ended December 31, 2001. Such policies have been continued without change. Also, refer to the notes to those financial statements for additional details of the Company's financial condition, results of operations, and cash flows. All the material items included in those notes have not changed except as a result of normal transactions in the interim, or as disclosed within this report. The accompanying interim consolidated financial statements have not been audited by independent accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations. Any and all adjustments are of a normal and recurring nature. The results of operations for the three and nine months ended September 30, 2002 are not necessarily indicative of results to be expected for the full year. The consolidated financial statements include the accounts of the Company, its wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian Abraxas") and Grey Wolf Exploration Inc. ("Grey Wolf"). Minority interest in 2001 represents the minority shareholders' proportionate share of the equity and income of Grey Wolf prior to the Company's acquiring the remaining interest in September 2001. Canadian Abraxas' and Grey Wolf's assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of shareholders' equity. Certain prior years balances have been reclassified for comparative purposes. Note 2. Business Conditions and Liquidity Requirements The accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The Company has experienced net losses from operations before taxes during the nine months ended September 30, 2002, of $143.1 million due primarily to proved property impairments of $116 million resulting primarily from volatile commodity prices - see Note 11. At September 30, 2002, the Company's current liabilities of approximately $86.7 million exceeded current assets of $22.6 million resulting in a working capital deficit of $64.2 million. The Company also had a stockholders' deficit of $138.0 million. The Company's principal sources of liquidity are cash on hand, cash flow from operations and proceeds from sales of assets and properties, in addition to funding remaining available under the Grey Wolf credit facility with Mirant Canada Energy Capital Ltd. The Company's continued existence as a going concern is dependent upon several current factors including the successful pursuit of financial restructuring alternatives and improvement in commodity prices. The Company will need additional funds on a timely basis for both the development of its assets and the service of its debt, including the repayment of the $63.5 million in principal amount of 12 7/8% Senior Secured notes or First Lien Notes maturing in March 2003 and the $191 million of 11 1/2 % Senior Secured Notes or Second Lien Notes and 11 1/2% Senior Notes or Old Notes maturing in November 2004 - see Note 4. In order to meet the current operating requirements of developing its assets and servicing its debt obligations, the Company will be required to obtain additional sources of liquidity and capital and/or reduce or reschedule its existing cash requirements including repayment of the First Lien Notes. In order to do so, the Company is actively pursuing one or more of the following alternatives: o selling all or a portion of its existing assets, including interests in its assets, or subsidiary operations; o negotiating the restructuring and/or refinancing of existing debt; o repaying debt with proceeds from the sale of assets; o exchanging debt for equity; o managing the timing and reducing the scope of its capital expenditures; or o issuing additional debt or equity securities or otherwise raising additional funds. 8 Due to the Company's current debt levels and the restrictions contained in the indentures governing the First Lien Notes, Second Lien Notes and Old Notes, the Company's primary opportunity for immediate additional sources of liquidity and capital will be through the disposition of assets of subsidiary operations and some of the other alternatives discussed above including the restructuring of existing debt. There can be no assurance that any of the above alternatives, or some combination thereof, will be available or, if available, will be on terms acceptable to the Company or that such efforts will produce enough cash to fund the Company's immediate operating and capital requirements or make timely interest payments and principal payments due on the First Lien Notes, Second Lien Notes and Old Notes. In order to meet the Company's need for current additional funds, the Planning Committee of the Board of Directors is actively pursuing several of the alternatives set forth above. The Planning Committee has engaged an investment banking firm to assist in the formulation of a plan of action for consideration by the Board of Directors. A proposed plan of action is expected before December 31, 2002. A refinancing or renegotiation of the Company's existing debt and the sale of additional assets likely will be required for the Company to meet its current liquidity and capital requirements. Management believes that a successful plan of action can be implemented to provide additional liquidity and capital, but no assurances can be given that the implementation of such a plan of action will result in the Company being able to continue as a going concern. The September 30, 2002 financial statements do not include any adjustments that might result from the outcome of these going concern uncertainties. Note 3. Divestiture of Assets In May of 2002, the wholly owned Canadian subsidiaries, Grey Wolf and Canadian Abraxas, sold their interest in a natural gas processing plant and associated crude oil and natural gas reserves in the Quirk Creek and Mahaska fields in Alberta, Canada for approximately $22.9 million. In June 2002, Abraxas sold its interest in the East White Point field in South Texas for approximately $9.8 million. The condensed pro forma financial information presented below summarizes on an pro forma basis, approximate results of the Company's consolidated results of operations for the three and nine months ended September 30, 2002, assuming the divestitures had occurred on January 1, 2002, and the three and nine months ended September 30, 2001, assuming the divestitures had occurred on January 1, 2001. Additionally, the pro forma information reflects an interest savings assuming that the Company had applied a portion of the proceeds to reacquire the Production Payment (see Note 4) on January 1st of the respective years.
---------------------------------- --------------------------------- Three Months Ended September 30, Nine months Ended September 30, ------------------ --------------- ---------------- ---------------- 2002 2001 2002 2001 -------------------------------------------------------------------- (in thousands, except per share data) ----------- ------------ --------------- -------------- Revenue ...................... $ 11,061 $ 13,078 $ 34,168 $ 54,911 =========== ============ =============== ============== Net loss ..................... (8,438) $ (6,044) $ (112,349) $ (10,726) =========== ============ =============== ============== Loss per common share--basic and diluted ........... $ (0.28) $ (0.27) $ (3.75) $ (0.44) =========== ============ =============== ==============
In July 2002, Canadian Abraxas and Grey Wolf sold their interest in the Millarville field in Alberta, Canada for approximately $1.1 million. Proceeds from these property sales were deposited with the Trustee for the First Lien Notes, to be held as restricted cash until disbursement to the Company under terms permitted by the indenture, or if not disbursed in accordance with the indentures governing the First Lien Notes, Second Lien Notes and Old Notes within 180 days of receipt, to be applied against the outstanding First Lien Notes. As of September 30, 2002 all of the funds had been disbursed to the Company. Note 4. Debt
Debt consists of the following: September 30 December 31 ------------ -------------- 2002 2001 ------------ -------------- (In thousands) 11.5% Senior Notes due 2004 ("Old Notes") ........................... $ 801 $ 801 12.875% Senior Secured Notes due 2003 ("First Lien Notes") .......... 63,500 63,500 9 11.5% Second Lien Notes due 2004 ("Second Lien Notes") .............. 190,178 190,178 9.5% Senior Credit Facility ("Grey Wolf Facility"), providing for borrowings up to approximately US $96 million (CDN $150 million) and secured by the assets of Grey Wolf and non-recourse to Abraxas, net of US $2.0 and $2.3 million discount at September 30, 002 and December 31, 2001, respectively ....................... 40,220 22,944 Production Payment ................................................. -- 8,176 -------- -------- 294,699 285,599 Less current maturities First Lien Notes .................................... 63,500 415 -------- -------- $231,199 $285,184 ======== ========
Old Notes. On November 14, 1996, the Company consummated the offering of $215.0 million of its 11.5% Senior Notes due 2004, Series A, which were exchanged for the Series B Notes in February 1997. On January 27, 1998, the Company completed the sale of $60.0 million of its 11.5% Senior Notes due 2004, Series C. The Series B Notes and the Series C Notes were subsequently combined into $275.0 million in principal amount of the Old Notes in June 1998. In December 1999, Abraxas and Canadian Abraxas completed an exchange offer which reduced the amount of outstanding Old Notes to $801,000. See the description of the Second Lien Notes below for more information. Interest on the Old Notes is payable semi-annually in arrears on May 1 and November 1 of each year at the rate of 11.5% per annum. The Old Notes are redeemable, in whole or in part, at the option of the Company at 100% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on November 1, 2002 and thereafter. The Old Notes are joint and several obligations of Abraxas and Canadian Abraxas and rank pari passu in right of payment to all existing and future unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes rank senior in right of payment to all future subordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes are, however, effectively subordinated to the First Lien Notes to the extent of the value of the collateral securing the First Lien Notes and to the Second Lien Notes to the extent of the value of the collateral securing the Second Lien Notes. The Old Notes are unconditionally guaranteed, on a senior basis by Sandia Oil and Gas Company ("Sandia") and Wamsutter Holdings, Inc. ("Wamsutter"), each of which is a wholly owned subsidiary of the Company. The guarantees are general unsecured obligations of Sandia and Wamsutter and rank pari passu in right of payment to all unsubordinated indebtedness of Sandia and Wamsutter and senior in right of payment to all subordinated indebtedness of Sandia and Wamsutter. The guarantees are effectively subordinated to the First Lien Notes and the Second Lien Notes to the extent of the value of the collateral securing the First Lien Notes and the Second Lien Notes. Upon a Change of Control, as defined in the Old Notes Indenture, each holder of the Old Notes will have the right to require the Company to repurchase all or a portion of such holder's Old Notes at a redemption price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. In addition, the Company will be obligated to offer to repurchase the Old Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase in the event of certain asset sales. First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5 million of the First Lien Notes. Interest on the First Lien Notes is payable semi-annually in arrears on March 15 and September 15, commencing September 15, 1999. Beginning March 15, 2002, the First Lien Notes are redeemable, in whole or in part, at the option of Abraxas at 100% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption. The First Lien Notes are senior indebtedness of Abraxas secured by a first lien on substantially all of the crude oil and natural gas properties of Abraxas and the shares of Grey Wolf owned by Abraxas. The First Lien Notes are unconditionally guaranteed on a senior basis, jointly and severally, by Canadian Abraxas, Sandia and Wamsutter, wholly-owned subsidiaries of the Company (the "Restricted Subsidiaries"). The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors and the shares of Grey Wolf owned by Abraxas and Canadian Abraxas. Upon a Change of Control, as defined in the First Lien Notes Indenture, each holder of the First Lien Notes will have the right to require Abraxas to repurchase such holder's First Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas will be obligated to offer to repurchase the First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales. 10 The First Lien Notes indenture contains certain covenants that limit the ability of Abraxas and certain of its subsidiaries, including the guarantors of the First Lien Notes to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas. The First Lien Notes indenture provides, among other things, that Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas or any other Restricted Subsidiary except in certain situations as described in the First Lien Notes indenture. Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas consummated an exchange offer whereby $269,699,000 of the Old Notes were exchanged for $188,778,000 of the Second Lien Notes, and 16,078,990 shares of Abraxas common stock and contingent value rights. An additional $5,000,000 of the Second Lien Notes were issued in payment of fees and expenses. Interest on the Second Lien Notes is payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2000. The Second Lien Notes are redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas at 100% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on December 1, 2002 and thereafter. The Second Lien Notes are senior indebtedness of Abraxas and Canadian Abraxas and are secured by a second lien on substantially all of the crude oil and natural gas properties of Abraxas and Canadian Abraxas and the shares of Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are unconditionally guaranteed on a senior basis, jointly and severally, by Sandia and Wamsutter. The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors. The Second Lien Notes are, however, effectively subordinated to the First Lien Notes and related guarantees to the extent the value of the collateral securing the Second Lien Notes and related guarantees and the First Lien Notes and related guarantees is insufficient to pay both the Second Lien Notes and the First Lien Notes. Upon a Change of Control, as defined in the Second Lien Notes Indenture, each holder of the Second Lien Notes will have the right to require Abraxas and Canadian Abraxas to repurchase such holder's Second Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas will be obligated to offer to repurchase the Second Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales. The Second Lien Notes indenture contains certain covenants that limit the ability of Abraxas and Canadian Abraxas and certain of their subsidiaries, including the guarantors of the Second Lien Notes (the "Restricted Subsidiaries") to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas or Canadian Abraxas. The Second Lien Notes indenture provides, among other things, that Abraxas and Canadian Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas, Canadian Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary except in certain situations as described in the Second Lien Notes indenture. The fair value of the Old Notes, First Lien Notes and Second Lien Notes was approximately $168.6 million as of September 30, 2002. The Company has approximately $325,000 of standby letters of credit and a $10,000 performance bond open at September 30, 2002. Approximately $336,000 of cash is restricted and in escrow related to certain of the letters of credit and the bond. 11 Grey Wolf Facility General. On December 20, 2001, Grey Wolf entered into a credit facility with Mirant Canada Energy Capital, Ltd. ("Mirant Canada"). The Grey Wolf Facility established a revolving credit facility with a commitment amount of CDN $150 million, (approximately US $96 million). Subject to certain restrictions, the borrowing base may be reduced at the discretion of Mirant Canada upon 30 days written notice. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date is December 20, 2007. The applicable interest rate charged on the outstanding balance under the Grey Wolf Facility is 9.5%. Any amounts in default will accrue interest at 15%. The Grey Wolf Facility is non-recourse to Abraxas and its properties, other than Grey Wolf properties, and Abraxas has no additional direct obligations to Mirant Canada under the facility. Principal Payments. Prior to maturity, Grey Wolf is required to make principal payments under the Grey Wolf Facility as follows: (i) on the date of the sale of any of its producing properties, Grey Wolf is required to make a payment equal to the amount of the net sales proceeds; (ii) on a monthly basis, Grey Wolf is required to make a payment equal to its net cash flow for the month prior to the date of the payment; and (iii) on the date that any reduction in the commitment amount becomes effective, Grey Wolf must repay all amounts over the commitment amount so reduced. Under the Grey Wolf Facility, "net cash flow" generally means the amount of proceeds received by Grey Wolf from the sale of hydrocarbons less taxes, royalty and similar payments (including overriding royalty interest payments made to Mirant Canada), interest payments made to Mirant Canada and operating and other expenses including approved capital and G&A expenses. Grey Wolf may also make pre-payments at any time after December 20, 2002 with no pre-payment penalty. The Company treats the Grey Wolf Facility as a revolving line of credit since, under ordinary circumstances, the lender is paid on a net cash flow basis. It is anticipated that the Company will be a net borrower for the next several years due to a large number of exploration and exploitation projects and the associated capital needs to complete the projects. Security. Obligations under the Grey Wolf Facility are secured by a security interest in substantially all of Grey Wolf's assets, including, without limitation, working interests in producing properties and related assets owned by Grey Wolf. None of Abraxas' assets are subject to a security interest under the Grey Wolf Facility. Covenants. The Grey Wolf Facility contains a number of covenants that, among other things, restrict the ability of Grey Wolf to (i) enter into new business areas, (ii) incur additional indebtedness, (iii) create or permit to be created any liens on any of its properties, (iv) make certain payments, dividends and distributions, (v) make any unapproved capital expenditures, (vi) sell any of its accounts receivable, (vii) enter into any unapproved leasing arrangements, (viii) enter into any take-or-pay contracts, (ix) liquidate, dissolve, consolidate with or merge into any other entity, (x) dispose of its assets, (xi) abandon any property subject to Mirant Canada's security interest, (xii) modify any of its operating agreements, (xiii) enter into any unapproved hedging agreements, and (xiv) enter into any new agreements affecting existing agreements relating to or affecting properties subject to Mirant Canada's security interests. In addition, Grey Wolf is required to submit a quarterly development plan for Mirant Canada's approval and Grey Wolf must comply with specified financial ratios and tests, including a minimum collateral coverage ratio. Grey Wolf was in compliance with these covenants at September 30, 2002. Upon receipt by the Company of a written request from Mirant Canada, the Company shall promptly, and in any event within 10 days of receipt of such request, have entered into one or more swap, hedge, floor, collar or similar agreements which are satisfactory to the lender at a price and for a term which is mutually acceptable to the Company and Mirant Canada. Events of Default. The Grey Wolf Facility contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in the financial condition of Grey Wolf. Overriding Royalty Interests. As a condition to the Grey Wolf Facility, Grey Wolf has granted two overriding royalty interests to Mirant Canada, each in the amount of 2.5% of the revenues received by Grey Wolf from oil and gas sales from all of its properties. These overriding royalty interests resulted in the recording of a $2.3 million discount on the Grey Wolf Facility borrowings at December 31, 2001. 12 Production Payment In October 1999, the Company entered into a non-recourse Dollar Denominated Production Payment agreement (the "Production Payment") with a third party. The Production Payment had an aggregate total availability of up to $50 million at 15% interest. The Production Payment related to a portion of the production from several natural gas wells in South Texas. The Company reacquired the Production Payment in June 2002, for approximately $6.8 million. Note 5. Earnings Per Share
The following table sets forth the computation of basic and diluted earnings per share: Three Months Ended September 30, Nine months Ended September 30, -------------------------------------- ----------------------------------- 2002 2001 2002 2001 ------------- -------------- ------------- ------------- Numerator: Net loss from continuing operations $ (8,438) $ (5,849) $ (112,827) $ (6,869) ------------- -------------- ------------- ------------- Denominator: Denominator for basic earnings per share - Weighted-average shares 29,979,397 22,626,599 29,979,397 24,347,669 Effect of dilutive securities: Stock options, warrants and CVR's - - - - ------------- -------------- ------------- ------------- Dilutive potential common shares Denominator for diluted earnings per share - adjusted weighted-average shares and assumed Conversions 29,979,397 22,626,599 29,979,397 24,347,669 Basic loss per share: Loss from continuing operations $ (0.28) $ (0.60) $ (3.76) $ (0.28) ============= ============== ============= ============= Diluted loss per share: Loss from continuing operations $ (0.28) $ (0.60) $ (3.76) $ (0.28) ============= ============== ============= =============
For the three and nine months ended September 30, 2002, none of the shares issuable in connection with stock options or warrants are included in diluted shares. Inclusion of these shares would be antidilutive due to losses incurred in the period. Had there not been losses in this period, dilutive shares would have been 3,000 shares and 6,487 shares for the three and nine months ended September 30, 2002, respectively. Contingent Value Rights ("CVRs") As part of the exchange offer consummated by the Company in December 1999, Abraxas issued contingent value rights or CVRs, which entitled the holders to receive up to a total of 105,408,978 shares of Abraxas common stock under certain circumstances as defined. On May 21, 2001, Abraxas issued 3,386,488 shares upon the expiration of the CVRs. Note 6. Guarantor Condensed Consolidating Financial Statements The following table presents condensed consolidating balance sheets of Abraxas, as a parent company, and its significant subsidiaries, Canadian Abraxas and Grey Wolf, as September 30, 2002 and December 31, 2001 and the related consolidating statements of operations and cash flows for the three and nine months ended September 30, 2002 and 2001. Canadian Abraxas is a guarantor of the First Lien Notes ($63.5 million) and jointly and severally liable with Abraxas for the Second Lien Notes ($190.2 million) and the Old Notes ($801,000). Grey Wolf is a non-guarantor with respect to the First Lien Notes, the Second Lien Notes, and the Old Notes. 13
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet September 30, 2002 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Assets: Current assets: Cash .................................... $ 8,694 $ 2,591 $ 2,073 $ - $ 13,358 Accounts receivable, less allowance for doubtful accounts...................... 3,472 4,836 10,584 (11,401) 7,491 Equipment inventory ..................... 870 179 12 - 1,061 Other current assets .................... 268 194 210 - 672 --------------- ------------- ------------ ------------- --------------- Total current assets .................. 13,304 7,800 12,879 (11,401) 22,582 Property and equipment - net................ 75,236 39,316 34,978 - 149,530 Deferred financing fees, net .............. 2,066 773 113 - 2,952 Other assets ............................... 108,709 787 8,381 (109,048) 8,829 --------------- ------------- ------------ ------------- --------------- Total assets ............................ $ 199,315 $ 48,676 $ 56,351 $ (120,449) $ 183,893 =============== ============= ============ ============= =============== Liabilities and Stockholders' deficit: Current liabilities: Accounts payable ............................. $ 13,917 $ 295 $ 8,285 $ (11,317) $ 11,180 Accrued interest ............................. 6,901 2,521 - - 9,422 Other accrued expenses ....................... 1,993 - - - 1,993 Hedge liability .............................. 354 290 - - 644 Current maturities of long-term debt ......... 63,500 - - - 63.500 --------------- ------------- ------------ ------------- --------------- Total current liabilities .................. 86,665 3,106 8,285 (11,317) 86,739 Long-term debt .................................. 138,350 52,629 40,220 - 231,199 Future site restoration ........................ - 3,274 713 - 3,987 --------------- ------------- ------------ ------------- --------------- 225,015 59,009 49,218 (11,317) 321,925 Stockholders' equity (deficit)................... (25,700) (10,333) 7,133 (109,132) (138,032) --------------- ------------- ------------ ------------- --------------- Total liabilities and stockholders' equity (deficit)........................................ $ 199,315 $ 48,676 $ 56,351 $ (120,449) $ 183,893 =============== ============= ============ ============= ===============
(1) Includes amounts for insignificant U.S. subsidiaries, Sandia and Wamsutter, which are guarantors of the First and Second Lien Notes. Sandia is also a guarantor of the Old Notes. Additionally, these subsidiaries are designated as Restricted Subsidiaries along with Canadian Abraxas.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet December 31, 2001 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Assets: Current assets: Cash .................................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605 Accounts receivable, less allowance for doubtful accounts...................... 17,281 792 6,782 (16,808) 8,047 Equipment inventory ..................... 1,061 178 12 - 1,251 Other current assets .................... 250 99 94 - 443 --------------- ------------- ------------ ------------- --------------- Total current assets .................. 22,185 2,314 9,655 (16,808) 17,346 14 Property and equipment - net................ 116,462 122,486 42,946 - 281,894 Deferred financing fees, net .............. 2,779 1,042 107 - 3,928 Other assets ............................... 108,704 784 6,281 (115,321) 448 --------------- ------------- ------------ ------------- --------------- Total assets ............................ $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616 =============== ============= ============ ============= =============== Liabilities and Stockholders' deficit: Current liabilities: Accounts payable ............................. $ 10,642 $ 17,009 $ 9,472 $ (22,985) $ 14,138 Accrued interest ............................. 5,000 1,009 4 - 6,013 Other accrued expenses ....................... 1,052 - 64 - 1,116 Hedge liability .............................. 438 220 - - 658 Current maturities of long-term debt ......... 415 - - - 415 --------------- ------------- ------------ ------------- --------------- Total current liabilities .................. 17,547 18,238 9,540 (22,985) 22,340 Long-term debt .................................. 209,611 52,629 22,944 - 285,184 Deferred income taxes ........................... - 17,718 2,903 - 20,621 Future site restoration ........................ - 3,399 657 - 4,056 --------------- ------------- ------------ ------------- --------------- 227,158 91,984 36,044 (22,985) 332,201 Stockholders' equity (deficit)................... 22,972 34,642 22,945 (109,144) (28,585) --------------- ------------- ------------ ------------- --------------- Total liabilities and stockholders' equity (deficit)........................................ $ 250,130 $ 126,626 $ 58,989 $ (132,129) $ 303,616 =============== ============= ============ ============= ===============
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the three months ended September 30, 2002 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Revenues: Oil and gas production revenues ............... $ 4,630 $ 2,657 $ 2,842 $ - $ 10,129 Gas processing revenues ....................... - 436 86 - 522 Rig revenues .................................. 169 - - - 169 Other ........................................ 1 184 56 - 241 ------------- ------------- ------------- ------------ ------------ 4,800 3,277 2,984 - 11,061 Operating costs and expenses: Lease operating and production taxes .......... 1,897 975 1,071 - 3,943 Depreciation, depletion, and amortization ..... 2,108 1,737 1,241 - 5,086 Rig operations ................................ 143 - - - 143 General and administrative .................... 686 426 287 - 1,399 ------------- ------------- ------------- ------------ ------------ 4,834 3,138 2,599 - 10,571 ------------- ------------- ------------- ------------ ------------ Operating income ................................. (34) 139 385 - 490 Other (income) expense: Interest income ............................... (15) - - - (15) Amortization of deferred financing fees........ 331 91 3 - 425 Interest expense............................... 6,119 1,656 841 - 8,616 ------------- ------------- ------------- ------------ ------------ 6,435 1,747 844 - 9,026 ------------- ------------- ------------- ------------ ------------ Loss from operations before income tax and extraordinary item............................. (6,469) (1,608) (459) - (8,536) Income tax benefit................................ - (8) (90) - (98) ------------- ------------- ------------- ------------ ------------ Net loss......................................... $ (6,469) $ (1,600) $ (369) $ - $ (8,438) ============= ============= ============ ============ ============
15
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the nine months ended September 30, 2002 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Revenues: Oil and gas production revenues ............... $ 14,592 $ 10,432 $ 9,134 $ - $ 34,158 Gas processing revenues ....................... - 1,593 340 - 1,933 Rig revenues .................................. 513 - - - 513 Other ........................................ 70 291 138 - 499 ------------- ------------- ------------- ------------ ------------ 15,175 12,316 9,612 - 37,103 Operating costs and expenses: Lease operating and production taxes .......... 5,666 2,809 2,730 - 11,205 Depreciation, depletion, and amortization ..... 7,167 9,030 4,813 - 21,010 Proved property impairment..................... 28,179 60,501 27,315 - 115,995 Rig operations ................................ 439 - - - 439 General and administrative .................... 2,893 787 898 - 4,578 ------------- ------------- ------------- ------------ ------------ 44,344 73,127 35,756 - 153,227 ------------- ------------- ------------- ------------ ------------ Operating loss.................................... (29,169) (60,811) (26,144) - (116,124) Other (income) expense: Interest income ............................... (56) - - - (56) Amortization of deferred financing fees........ 994 274 15 - 1,283 Interest expense............................... 18,650 4,998 2,142 - 25,790 ------------- ------------- ------------- ------------ ------------ 19,588 5,272 2,157 - 27,017 ------------- ------------- ------------- ------------ ------------ Loss from operations before income tax and extraordinary item............................. (48,757) (66,083) (28,301) - (143,141) Income tax benefit................................ - (18,522) (11,792) - (30,314) ------------- ------------- ------------- ------------ ------------ Net loss......................................... $ (48,757) $ (47,561) $ (16,509) $ $ (112,827) ------------- ------------- ------------- ------------ ------------
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the three months ended September 30, 2001 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Revenues: Oil and gas production revenues ............... $ 7,485 $ 4,114 $ 2,068 $ - $ 13,667 Gas processing revenues ....................... - 677 100 - 777 Rig revenues .................................. 199 - - - 199 Other ........................................ 3 164 91 - 258 ------------- ------------- ------------- ------------ ------------ 7,687 4,955 2,259 - 14,901 Operating costs and expenses: Lease operating and production taxes .......... 2,096 1,735 657 - 4,488 Depreciation, depletion, and amortization ..... 3,397 3,431 1,193 - 8,021 Rig operations ................................ 204 - - - 204 General and administrative .................... 945 280 142 - 1,367 16 General and administrative (Stock-based Compensation)................................ (1,366) - - - (1,336) ------------- ------------- ------------- ------------ ------------ 5,276 5,446 1,992 - 12,714 ------------- ------------- ------------- ------------ ------------ Operating income (loss)........................... 2,411 (491) 267 - 2,187 Other (income) expense: Interest income ............................... (226) - - 180 (46) Amortization of deferred financing fees........ 347 58 - - 405 Interest expense .............................. 6,384 1,789 97 (180) 8,090 ------------- ------------- ------------- ------------ ------------ 6,505 1,847 97 - 8,449 ------------- ------------- ------------- ------------ ------------ Income (loss) from operations before income tax and extraordinary item......................... (4,094) (2,338) 170 - (6,262) Income tax expense (benefit)...................... - (677) 69 - (608) Minority interest in income of consolidated 112 foreign subsidiary ............................ - - - (195) (195) ------------- ------------- ------------- ------------ ------------ Net income (loss)................................. $ (4,094) $ (1,661) $ 101 $ (195) $ (5,849) ============= ============ ============= ============ ============
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the nine months ended September 30, 2001 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Revenues: Oil and gas production revenues ............... $ 30,033 $ 20,537 $ 11,473 $ - $ 62,043 Gas processing revenues ....................... - 1,470 241 - 1,711 Rig revenues .................................. 607 - - - 607 Other ........................................ 82 399 261 - 742 ------------- ------------- ------------- ------------ ------------ 30,722 22,406 11,975 - 65,103 Operating costs and expenses: Lease operating and production taxes .......... 6,837 5,084 1,758 - 13,679 Depreciation, depletion, and amortization ..... 9,584 11,587 3,979 - 25,150 Rig operations ................................ 548 - - - 548 General and administrative .................... 3,495 979 577 - 5,051 General and administrative (Stock-based Compensation)................................ (2,767) - - - (2,767) ------------- ------------- ------------- ------------ ------------ 17,697 17,650 6,314 - 41,661 ------------- ------------- ------------- ------------ ------------ Operating income ................................ 13,025 4,756 5,661 - 23,442 Other (income) expense: Interest income ............................... (930) - - 856 (74) Amortization of deferred financing fees........ 1,042 273 - - 1,315 Interest expense .............................. 18,815 5,413 328 (856) 23,700 Other ......................................... 16 - - - 16 ------------- ------------- ------------- ------------ ------------ 18,943 5,686 328 - 24,957 ------------- ------------- ------------- ------------ ------------ Income (loss) from operations before income tax and extraordinary item......................... (5,918) (930) 5,333 - (1,515) Income tax expense ............................... 505 1,048 2,124 - 3,677 Minority interest in income of consolidated 112 foreign subsidiary ............................ - - - (1,676) (1,676) ------------- ------------- ------------- ------------ ------------ Net loss.......................................... $ (6,423) $ (1,978) $ 3,209 $ (1,676) $ (6,868) ============= ============= ============= ============ ============
17
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the Nine months ended September 30, 2002 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Operating Activities Net loss .................................... $ (48,757) $ (47,561) $ (16,509) $ - $ (112,827) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion, and amortization ......................... 7,167 9,030 4,813 - 21,010 Proved property impairment.............. 28,179 60,501 27,314 - 115,994 Deferred income tax benefit............. - (18,522) (11,792) - (30,314) Amortization of deferred financing fees. 994 274 16 - 1,284 Amortization of debt discount........... - - 287 - 287 Changes in operating assets and liabilities: Accounts receivable ................ 19,401 (20,786) 2,441 (557) 499 Equipment inventory ................ 191 - - - 191 Other ............................. (22) (165) (62) - (249) Accounts payables and accrued expenses ......................... 525 1,520 (1,297) 557 1,305 ------------- ------------- ------------- ------------ ------------ Net cash provided (used) by operating activities ............................... 7,678 (15,709) 5,211 - (2,820) Investing Activities Capital expenditures, including purchases and development of properties............. (3,845) (4,462) (25,085) - (33,392) Proceeds from sale of oil and gas properties. 9,725 21,669 2,284 - 33,678 ------------- ------------- ------------- ------------ ------------ Net cash provided (used) by investing activities ............................... 5,880 17,207 (22,801) - 286 Financing Activities Proceeds from long-term borrowings .......... - - 17,084 - 17,084 Payments on long-term borrowings ............ (8,176) - - - (8,176) Deferred financing fees...................... (281) (22) (303) ------------- ------------- ------------- ------------ ------------ Net cash provided (used) by financing Activities.................................. (8,457) - 17,062 - 8,605 ------------- ------------- ------------- ------------ ------------ Effect of exchange rate changes on cash ..... - (152) (166) - (318) ------------- ------------- ------------- ------------ ------------ Increase (decrease) in cash ................. 5,101 1,346 (694) - 5,753 Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605 ------------- ------------- ------------- ------------ ------------ Cash at end of year.......................... $ 8,694 $ 2,591 $ 2,073 $ - $ 13,358 ============= ============= ============= ============ ============
18
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the nine months ended September 30, 2001 (In thousands) Abraxas Petroleum Restricted Reclassifi- Abraxas Corporation Subsidiary Non-Guarantor cations Petroleum Inc. - Parent (Canadian Subsidiary and Corporation and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries ------------- ------------- ------------- ------------ ------------ Operating Activities Net income (loss) ........................... $ (6,423) $ (2,062) $ 2,815 $ (1,198) $ (6,868) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority interest in income of foreign subsidiary ........................... - - - 1,676 1,676 Depreciation, depletion, and amortization ......................... 9,585 11,587 3,978 - 25,150 Deferred income tax expense ............ - 878 2,079 - 2,957 Amortization of deferred financing fees. 1,042 273 - - 1,315 Stock-based compensation ............... (2,767) - - - (2,767) Changes in operating assets and liabilities: Accounts receivable ................ 20,727 (8,817) 1,688 - 13,598 Equipment inventory ................ (234) - - - (234) Accounts payables and accrued expenses ......................... (7,280) 364 (1,822) - (8,738) ------------- ------------- ------------- ------------ ------------ Net cash provided by operating activities ... 14,650 2,223 8,738 478 26,089 Investing Activities Capital expenditures, including purchases and development of properties ............ (15,984) (14,340) (13,991) (478) (44,793) Proceeds from sale of oil and gas properties ............................... - 11,968 3,393 - 15,361 Acquisition of minority interest............. (2,248) - - - (2,248) ------------- ------------- ------------- ------------ ------------ Net cash used by investing activities ...... (18,232) (2,372) (10,598) (478) (31,680) Financing Activities Proceeds from long-term borrowings .......... 11,256 - 1,610 - 12,866 Payments on long-term borrowings ............ (8,873) - - - (8,873) Exercise of stock options ................... 16 - - - 16 Other........................................ (52) - 283 - 231 ------------- ------------- ------------- ------------ ------------ Net cash provided by financing activities .. 2,347 - 1,893 - 4,240 ------------- ------------- ------------- ------------ ------------ Effect of exchange rate changes on cash ..... - (128) (33) - (161) ------------- ------------- ------------- ------------ ------------ Decrease in cash ............................ (1,235) (277) - - (1,512) Cash at beginning of period ................. 326 1,678 - - 2,004 ------------- ------------- ------------- ------------ ------------ Cash at end of period........................ $ (909) $ 1,401 $ - $ - $ 492 ============= ============= ============= ============ ============
19 Note 7. Business Segments Business segment information about the three months and nine months ended September 30, 2002 in different geographic areas is as follows:
Three Months Ended September 30, 2002 ------------------------------------------------------------- U.S. Canada Total ------------------ ----------------- ------------------- (In thousands) Revenues ............................... $ 4,800 $ 6,261 $ 11,061 ================== ================ =================== Operating loss.......................... $ 651 $ 525 $ 1,176 ================== ================ General Corporate................................................................. (686) Interest expense and amortization of deferred financing fees........................................................ (9,026) ------------------- Loss before income taxes.......................................................... $ (8,536) =================== Three Months Ended September 30, 2001 ------------------------------------------------------------- U.S. Canada Total ------------------ ----------------- ------------------- (In thousands) Revenues ............................... $ 7,687 $ 7,214 $ 14,901 ================== ================= =================== Operating profit........................ $ 2,170 $ (224) $ 1,946 ================== ================= General Corporate................................................................. 241 Interest expense and amortization of deferred financing fees........................................................ (8,449) ------------------- Income before income taxes........................................................ $ (6,262) =================== Nine months Ended September 30, 2002 ------------------------------------------------------------- U.S. Canada Total ------------------ ----------------- ------------------- (In thousands) Revenues ............................... $ 15,175 $ 21,928 $ 37,103 ================== ================= =================== Operating loss.......................... $ (26,187) $ (86,954) $ (113,141) ================== ================= General Corporate................................................................. (2,983) Interest expense and amortization of deferred financing fees........................................................ (27,017) ------------------- Loss before income taxes.......................................................... $ (143,141) =================== Nine months Ended September 30, 2001 ------------------------------------------------------------- U.S. Canada Total ------------------ ----------------- ------------------- (In thousands) Revenues ............................... $ 30,722 $ 34,381 $ 65,103 ================== ================= =================== Operating profit........................ $ 14,023 $ 10,417 $ 24,440 ================== ================= General Corporate................................................................. (998) Interest expense and amortization of deferred financing fees........................................................ (24,957) ------------------- Income before income taxes........................................................ $ (1,515) =================== At September 30, 2002 ------------------------------------------------------------- U.S. Canada Total ------------------ ----------------- ------------------- (In thousands) Identifiable assets .................... $ 88,659 $ 83,168 $ 171,827 ================== ================= Corporate assets.................................................................. 12,066 ------------------- Total assets ..................................................................... $ 183,893 =================== At December 31, 2001 ------------------------------------------------------------- U.S. Canada Total ------------------ ----------------- ------------------- (In thousands) 20 Identifiable assets .................... $ 124,993 $ 174,063 $ 299,056 ================== ================= Corporate assets.................................................................. 4,560 ------------------- Total assets ..................................................................... $ 303,616 ===================
Note 8. Hedging Program and Derivatives On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, the Company uses only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Other Comprehensive Income/Loss, a component of Stockholders' Equity, to the extent that the hedge is effective. Any ineffective portion is reflected in current operations. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in Accumulated Other Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective, remain unchanged until the related production is delivered. If the Company determines that it is probable that a hedged transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. Gains and losses on hedging instruments related to Accumulated Other Comprehensive Income/Loss and adjustments to carrying amounts on hedged production are included in natural gas or crude oil production revenue in the period that the related production is delivered. The following table sets forth the Company's hedge position as of September 30, 2002.
Time Period Notional Quantities Price Fair Value - -------------------------------------- ---------------------------------- ------------------------------ ------------ October 1, 2002 - October 31, 2002 20,000 Mcf/day of natural gas Fixed price swap $2.60-$2.95 $(0.6) or 1,000 Bbl/day of crude oil natural gas or million $18.90 Crude oil
On January 1, 2001, in accordance with the transition provisions of SFAS 133, the Company recorded $31.0 million, net of tax, in Other Comprehensive Income/Loss representing the cumulative effect of an accounting change to recognize the fair value of cash flow derivatives. The Company recorded cash flow hedge derivative liability of $38.2 million on that date and a deferred tax asset of $7.2 million. During the first nine months of 2002 the fair value of the hedge increased by $2.5 million. For the three and nine months ended September 30, 2002, the ineffective portion of the cash flow hedges were not material. As of September 30, 2002, $0.5 million of deferred net losses on derivative instruments were recorded in other comprehensive income, of which $0.5 million is expected to be reclassified to earnings upon the expiration of the hedge in October 2002. All hedge transactions are subject to the Company's risk management policy, which has been approved by the Board of Directors. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Note 9. Contingencies Litigation - In 2001 the Company and a limited partnership, of which a subsidiary of the Company is the general partner (the "Partnership"), were named in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserts breach of contract, fraud and negligent misrepresentation by the Company and the Partnership related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by the Company and the Partnership. 21 In February 2002, a summary judgment was granted to the plaintiff in this matter and a final judgment in the amount of $1.3 million was entered. The Company and the Partnership have filed an appeal. The Company believes these charges are without merit. The Company has established a reserve in the amount of $845,000, which represents the Company's share of the judgment. The Company believes that the remaining portion of the judgment represents the other partner's share of such judgment. In late 2000, the Company received a Final De Minimis Settlement Offer from the United States Environmental Protection Agency concerning the Casmalia Disposal Site, Santa Barbara County, California. The Company's liability for the cleanup at the Superfund site is based on its acquisition of Bennett Petroleum Corporation, which is alleged to have transported or arranged for the transportation of oil field waste and drilling muds to the Superfund site. The Company has engaged California counsel to evaluate the notice of proposed de minimis settlement and its notice of potential strict liability under the Comprehensive Environmental Response, Compensation and Liability Act. Defense of the action is handled through a joint group of oil companies, all of which are claiming a petroleum exclusion that would limit the Company's liability. The potential financial exposure and any settlement posture has yet not been developed, but is considered by the Company to be immaterial. Additionally, from time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At September 30, 2002, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company. Note 10. Comprehensive Income Comprehensive income includes net income, losses and certain items recorded directly to Stockholders' Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of comprehensive loss for the three and nine months ended September 30, 2002:
Accumulated Other Comprehensive Comprehensive Income (Loss) Income (Loss) --------------------------- ---------------- Nine Three As of Months Months September 30, Ended Ended 2002 September 30, 2002 ---------------- (In thousands) ---------------------------- --------------- Accumulated other comprehensive loss at December 31, 2001 .............................................. $ (13,561) Net loss .................................................... $(112,827) $ (8,438) Other Comprehensive loss: Hedging derivatives (net of tax) - See Note Reclassification adjustment for settled hedge contracts ........................................... 2,034 883 Change in fair market value of outstanding hedge positions ............................... (1,980) (4) Foreign currency translation adjustment 3,326 (1,830) --------- --------- Other comprehensive income (loss) ............................... 3,380 (951) 3,380 --------- --------- Comprehensive loss .............................................. $(109,447) $ (9,389) ========= ========= --------- Accumulated other comprehensive loss at September 30, 2002 ....... $ (10,181) =========
22 Note 11. Proved Property Impairment In accordance with the Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of a period, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the Company's financial statements. As of June 30, 2002, the Company's net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $138.7 million ($28.2 million on the U.S. properties and $110.5 million on the Canadian properties). These amounts were calculated considering June 30, 2002 period-end prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company used the subsequent increased prices in Canada to evaluate its Canadian properties, and reduced the period end June 30, 2002 write-down to an amount of $87.8 million on those properties. The subsequent prices in the U.S. would not have resulted in a reduction of the write-down for the U.S. properties. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. At September 30, 2002 the Company's net capitalized cost of crude oil and natural gas properties did not exceed the present value of its estimated reserves, due to increased commodity prices during the third quarter and as such no write down was recorded for the three months ended September 30, 2002. The Company cannot assure you that it will not experience additional write-downs in the future. Should commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our crude oil and natural gas properties may be required. Note 12. New Accounting Standards In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires an asset retirement obligation to be recorded at fair value during the period incurred and an equal amount recorded as an increase in the value of the related long-lived asset. The capitalized cost is depreciated over the useful life of the asset and the obligation is accreted to its present value each period. SFAS No. 143 is effective for the Company beginning January 1, 2003. The Company is currently evaluating the impact the standard will have on its future results of operations and financial condition. Effective January 1, 2002, the Company adopted SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 retains the requirement to recognize an impairment loss only where the carrying value of a long-lived asset is not recoverable from its undiscounted cash flows and to measure such loss as the difference between the carrying amount and fair value of the asset. SFAS No. 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. This new standard had no impact on the Company's consolidated financial statements during the first nine months of 2002. In April 2002, the FASB issued SFAS No. 145, "Recission of FASB No. 4, 44, and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS No. 145 clarifies guidance related to the reporting of gains and losses from extinguishment of debt and resolves inconsistencies related to the required accounting treatment of certain lease modifications. SFAS No. 145 also amends other existing pronouncements to make various technical corrections, clarify meanings or describe their applicability under changed conditions. The provisions relating to the reporting of gains and losses from extinguishment of debt become effective for the Company beginning January 1, 2003 with earlier adoption encouraged. All other provisions of this standard have been effective for the Company as of May 15, 2002 and did not have a significant impact on its financial condition or results of operations. In June 2002, the FASB issued SFAS No. 146, "Accounting for Cost Associated with Exit or Disposal Activities." SFAS No. 146 requires costs associated with exit of disposal activities to be recognized when they are incurred rather than at the date of commitment to an exit or disposal plan. SFAS No. 146 is effective for the Company beginning January 1, 2003. The Company is currently evaluating the impact the standard will have on its results of operations and financial condition. The American Institute of Certified Public Accountants has issued an Exposure Draft for a Proposed Statement of Position, "Accounting for Certain Costs and Activities Related to Property, Plant and Equipment" which would require major maintenance activities to be expensed as costs are incurred. The Company is currently evaluating the impact on its results of operations and financial condition if this proposed Statement of Position is adopted in its current form. 23 PART I Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following is a discussion of our financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our consolidated financial statements and the notes thereto, included in our Annual Report on Form 10-K filed for the year ended December 31, 2001. Critical Accounting Policies There have been no changes from the Critical Accounting Policies described in the Company's Annual Report on Form 10-K for the year ended December 31, 2001. General We have incurred net losses in four of the last five years and for the first nine months of 2002, and there can be no assurance that operating income and net earnings will be achieved in future periods. Our revenues, profitability and future rate of growth are substantially dependent upon prevailing prices for crude oil and natural gas and the volumes of crude oil, natural gas and natural gas liquids we produce. Natural gas and crude oil prices weakened during 1998. Crude oil and natural gas prices increased somewhat in 1999 and increased substantially in 2000. During 2001, crude oil and natural gas prices weakened substantially from the 2000 levels. During the first nine months of 2002, prices began to increase. In addition, because our proved reserves will decline as crude oil, natural gas and natural gas liquids are produced, unless we acquire additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploitation, exploration and development projects. In order to provide us with liquidity and capital resources, we have sold certain of our producing properties. However, our production levels have declined as we have been unable to replace the production represented by the properties we have sold with new production from the producing properties we have invested in with the proceeds of our property sales. If crude oil and natural gas prices return to the depressed levels experienced in the last nine months of 2001, or if our production levels continue to decrease, our revenues, cash flow from operations and financial condition will be materially adversely affected. For more information, see "Liquidity and Capital Resources-Current Liquidity Requirements" and "-Future Capital Resources." Results of Operations Our financial results depend upon many factors, particularly the following factors which most significantly affect our results of operations: o the sales prices of crude oil, natural gas liquids and natural gas; o the level of total sales volumes of crude oil, natural gas liquids and natural gas; o the ability to raise capital resources and provide liquidity to meet cash flow needs; o the level of and interest rates on borrowings; and o the level and success of exploration and development activity. Price volatility in the natural gas market has remained prevalent in the last few years. In the first quarter of 2002, we experienced a decline in energy commodity prices from the prices that we received in the first quarter of 2001. During the first quarter of 2001, we had certain crude oil and natural gas hedges in place that prevented us from realizing the full impact of a favorable price environment. In January 2001, the market price of natural gas was at its highest level in our operating history and the price of crude oil was also at a high level. However, over the course of 2001 and the beginning of the first quarter of 2002, prices again became depressed, primarily due to the economic downturn. Beginning in March 2002, commodity prices began to increase and continued higher through September 2002. The table below illustrates how natural gas prices fluctuated over the course of 2001 and the first two quarters of 2002. The table below contains the last three days average of NYMEX traded contracts index price and the prices we realized during each quarter for 2001 and the first three quarters of 2002, including the impact of our hedging activities. 24
(in $ per Mcf) Natural Gas Prices by Quarter ----------------------------------------------------------------------------------------------------- Quarter Ended ----------------------------------------------------------------------------------------------------- March 31, June 30, September 30, December 31, March 31, June 30, September 30, 2001 2001 2001 2001 2002 2002 2002 -------------- ---------- ---------------- ---------------- ------------- ---------- ---------------- Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 $ 2.38 $ 3.36 $ 3.28 Realized 4.85 3.41 2.26 2.09 2.21 2.44 2.08
The NYMEX natural gas price on November 11, 2002 was $ 3.78 per Mcf. Prices for crude oil have followed a similar path as the commodity market fell throughout 2001and the first quarter of 2002. The table below contains the last three days average of NYMEX traded contracts index price and the prices we realized during each quarter for 2001 and the first three quarters of 2002.
(in $ per Bbl) Crude Oil Prices by Quarter Quarter Ended ------------------------------------------------------------------------------------------------------ March 31, June 30, September 30, December 31, March 31, June 30, September 30, 2001 2001 2001 2001 2002 2002 2002 -------------- --------- ----------------- --------------- ------------- ----------- ----------------- Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48 $ 26.40 $ 27.50 Realized 27.22 25.32 25.06 18.72 16.64 23.47 27.19
The NYMEX crude oil price on November 11, 2002 was $ 25.94 per Bbl. Hedging Activities. Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. As of September 30, 2002, we had an open position on a swap call agreement for either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day, at the counterparty's option, at fixed prices ($18.90 for crude oil or $2.95 to $2.60 for natural gas) through October 31, 2002. As of September 30, 2002, the fair market value of the remaining fixed price hedge agreement was a liability of approximately $0.6 million, which is expected to be charged to revenues in 2002. Selected operating data. The following table sets forth certain of our operating data for the periods presented.
Three Months Ended Nine months Ended September 30 September 30 2002 2001 2002 2001 ------------------------------------------------------------- ------------ Operating Revenue (in thousands): Crude Oil Sales ................................ $ 1,801 $ 2,968 $ 4,799 $ 9,674 Natural Gas Sales ................................ 7,277 9,640 26,345 47,504 Natural Gas Liquids Sales......................... 1,051 1,059 3,014 4,865 Processing Revenue................................ 522 777 1,933 1,711 Rig Operations.................................... 169 199 513 607 Other............................................. 241 258 499 742 ----------- ----------- ------------- ------------ $ 11,061 $ 14,901 $ 37,103 $ 65,103 =========== =========== ============= ============ Operating Income (Loss) (in thousands)............ $ 490 $ 2,187 $ (116,124) $ 23,442 Crude Oil Production (MBBLS)...................... 66 118 216 373 Natural Gas Production (MMCFS).................... 3,501 4,264 11,692 13,420 Natural Gas Liquids Production (MBBLS)............ 52 59 182 203 Average Crude Oil Sales Price ($/BBL)............. $ 27.19 $ 25.06 $ 22.27 $ 25.91 Average Natural Gas Sales Price ($/MCF)........... $ 2.08 $ 2.26 $ 2.25 $ 3.54 Average Liquids Sales Price ($/BBL)............... $ 20.04 $ 18.05 $ 16.53 $ 24.02
25 Comparison of Three Months Ended September 30, 2002 to Three Months Ended September 30, 2001 Operating Revenue. During the three months ended September 30, 2002, operating revenue from crude oil, natural gas and natural gas liquid sales decreased to $10.1 million compared to $13.7 million in the three months ended September 30, 2001. The decrease in revenue was primarily due to decreased production volumes during the period together with a decline in natural gas prices. The decline in production volumes was the result of disposition of producing properties in the second quarter of 2002, natural field declines and our inability to replace the production represented by the properties we have sold with new production from the producing properties we invested in with the proceeds of our property sales. Lower natural gas prices reduced crude oil and natural gas revenue by $0.7 million which was offset somewhat by higher realized prices for crude oil and natural gas liquids. Decreased production volumes reduced revenue by $3.1 million for the quarter ended September 30, 2002 as compared to the same period in 2001. Average sales prices net of hedging losses for the quarter ended September 30, 2002 were: o $ 27.19 per Bbl of crude oil, o $ 20.04 per Bbl of natural gas liquid, and o $ 2.08 per Mcf of natural gas Average sales prices net of hedging losses for the quarter ended September 30, 2001 were: o $25.06 per Bbl of crude oil, o $18.05 per Bbl of natural gas liquid, and o $ 2.26 per Mcf of natural gas Crude oil production volumes declined from 118.4 MBbls during the quarter ended September 30, 2001 to 66.3 MBbls for the same period of 2002. This decline resulted from a de-emphasis on crude oil drilling in prior periods, the disposition of crude oil producing properties in the later part of 2001 and the first nine months of 2002, and a natural decline in production. Natural gas production volumes declined to 3,501 MMcf for the three months ended September 30, 2002 from 4,264 MMcf for the same period of 2001. This decline was primarily due to the sale of producing properties in late 2001 and the first nine months of 2002 and the natural decline in production which was partially offset by new production from current drilling activities. Lease Operating Expenses. Lease operating expenses and natural gas processing costs ("LOE") for the three months ended September 30, 2002 decreased to $3.9 million from $4.5 million for the same period in 2001. The decrease in LOE is primarily due to a decrease in production tax expense due to lower natural gas prices in the quarter ended September 30, 2002 as compared to the same period of 2001. Our LOE on a per MCFE basis for the three months ended September 30, 2002 was $0.93 per MCFE compared to $0.84 for the same period of 2001. General and adminsitrative ("G&A") Expenses. G&A expenses remained constant at $1.4 million for the quarter ended September 30, 2002 and for the same period of 2001. G&A expense on a per MCFE basis was $0.33 for the third quarter of 2002 compared to $0.26 for the same period of 2001. The increase on a per MCFE basis was due to a decline in production volumes during the third quarter of 2002 as compared to the same period in 2001. G&A - Stock-based Compensation. Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and not exercised prior to July 1, 2000, require that the awards be accounted for as variable expenses until they are exercised, forfeited, or expired. In March 1999, we amended the exercise price to $2.06 per share on all options with an existing exercise price greater than $2.06 per share. We recognized income of approximately $1.4 million during the quarter ended September 30, 2001 related to these repricings. This income was recorded as a reduction of expense. The income recognized in the third quarter of 2001 was due to a decline in the price of our common stock. During 2002, we did not recognize any stock-based compensation because the price of our common stock has remained below the exercise price. Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization ("DD&A") expense decreased to $5.1 million for the three months ended September 30, 2002 from $8.0 million for the same period of 2001. Our DD&A on a per MCFE basis for the three months ended September 30, 2002 was $1.21 per MCFE as compared to $1.51 in 2001. The decrease was due to a reduction in the full cost pool from property sales and the proved property impairment that was recorded in the second quarter of 2002. 26 Interest Expense. Interest expense increased to $8.6 million for the third quarter of 2002 compared to $8.1 million in 2001. The increase was due to an increase in long-term debt primarily relating to increased borrowings under the Grey Wolf credit facility. Minority interest. We owned a 49% controlling interest in the earnings of Grey Wolf through August 2001. The consolidated financial statements include the results of Grey Wolf. The net income attributable to the minority interest in Grey Wolf for the third quarter of 2001 was $195,000. As of September 30, 2002, we owned 100% of the outstanding capital stock of Grey Wolf. We obtained the additional interest in Grey Wolf pursuant to a tender offer and subsequent compulsory merger, completed in September 2001. Income taxes. Income taxes increased to a benefit of $98,000 for the three months ended September 30, 2002 compared to a benefit of $608,000 for the same period of 2001. There is no current or deferred income tax benefit for the U.S. net losses due the valuation allowance which has been recorded against such benefits. This results in a low consolidated effective tax rate for the three months ended September 30, 2002. Comparison of Nine months Ended September 30, 2002 to Nine months Ended September 30, 2001 Operating Revenue. During the nine months ended September 30, 2002, operating revenue from crude oil, natural gas and natural gas liquid sales decreased to $34.2 million as compared to $62.0 million in the nine months ended September 30, 2001. The decrease in revenue was primarily due to decreased prices realized during the period, as well as a decrease in production volumes. Production volumes decreased primarily as a result of producing property sales in the later part of 2001 and in the first nine months of 2002. Lower commodity prices impacted crude oil and natural gas revenue by $20.1 million while reduced production volumes had a $7.7 million negative impact on revenue. Average sales prices net of hedging losses for the nine months ended September 30, 2002 were: o $ 22.27 per Bbl of crude oil, o $ 16.53 per Bbl of natural gas liquid, and o $ 2.25 per Mcf of natural gas Average sales prices net of hedging losses for the nine months ended September 30, 2001 were: o $25.91 per Bbl of crude oil, o $24.02 per Bbl of natural gas liquid, and o $ 3.54 per Mcf of natural gas Crude oil production volumes declined from 373.4 MBbls during the nine months ended September 30, 2001 to 215.5 MBbls for the same period of 2002, primarily as a result of a de-emphasis on crude oil drilling in prior periods, and the sale of crude oil producing properties in the later part of 2001 and in the first half of 2002. Natural gas production volumes declined to 11,692 MMcf for the nine months ended September 30, 2002 from 13,420 MMcf for the same period of 2001. This decline was primarily due to the sale of properties in late 2001 and the first half of 2002 and the natural decline in production which was partially offset by new production from current drilling activities. Lease Operating Expenses. Lease operating expenses and natural gas processing costs ("LOE") for the nine months ended September 30, 2002 decreased to $11.2 million from $13.7 million for the same period in 2001. The decrease in LOE was primarily due to a decrease in production tax expense due to higher commodity prices in the nine months ended September 30, 2001 as compared to the same period of 2002 and a reduction in the number of producing wells due to property sales. LOE on a per MCFE basis for the nine months ended September 30, 2002 was $0.80 per MCFE as compared to $0.81 for the same period of 2001. General and adminsitrative ("G&A") Expenses. G&A expenses decreased from $5.1 million for the first nine months of 2001 to $4.6 million for the first nine months of 2002. G&A expense on a per MCFE basis was $0.33 for the first nine months of 2002 compared to $0.30 for the same period of 2001. The decrease in G&A expense was primarily due to a decrease in consulting fees in 2002 as compared to 2001. G&A - Stock-based Compensation. Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of Accounting Principles Board Opinion No. ("APB") 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and not exercised prior to July 1, 2000, require that the awards be accounted for as variable expenses until they are exercised, 27 forfeited, or expired. In March 1999, we amended the exercise price to $2.06 per share on all options with an existing exercise price greater than $2.06 per share. We recognized income of approximately $2.8 million during the nine months ended September 30, 2001 related to these repricings. The income was recorded as a reduction of expense. The income recognized in 2001 was due to a decline in the price of our common stock. During 2002, we did not recognize any stock - -based compensation due to the decline in the price of our common stock. Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization ("DD&A") expense decreased to $21.0 million for the nine months ended September 30, 2002 from $25.2 million for the same period of 2001. Our DD&A on a per MCFE basis for the nine months ended September 30, 2002 was $1.49 per MCFE as compared to $1.49 in 2001. These decreases were due to reduced production volumes in 2002 and reduction in the full cost pool as a result of prior ceiling limitation write-downs. Interest Expense. Interest expense increased to $25.8 million for the first nine months of 2002 compared to $23.7 million in 2001. The increase was due to an increase in long-term debt primarily relating to the Grey Wolf credit facility. Proved Property Impairment. We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting for crude oil and natural gas properties. Under this method, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties less related deferred taxes, is limited by country, to the lower of the unamortized cost or the cost ceiling, (defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes.) If the net capitalized cost of crude oil and natural gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings, which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. The risk that we will be required to write-down the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. As of June 30, 2002, our net capitalized costs of crude oil and natural gas properties exceeded the present value of our estimated proved reserves by $138.7 million ($28.2 million on the U.S. properties and $110.5 million on the Canadian properties). As a result, during the nine months ended September 30, 2002, we incurred a proved-property impairment write-down of approximately $116 million primarily due to volatile commodity prices. These amounts were calculated considering June 30, 2002 period-end prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. We used the subsequent prices to evaluate our Canadian properties, and reduced the period end June 30, 2002 write-down to an amount of $87.8 million on those properties. The subsequent prices in the U.S. would not have resulted in a reduction of the write-down for the U.S. properties. At September 30, 2002 the Company's net capitalized cost of crude oil and natural gas properties did not exceed the present value of its estimated reserves, due to increased commodity prices during the third quarter and as such no further write-down was recorded. We cannot assure you that we will not experience additional write-downs in the future. Should commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our crude oil and natural gas properties may be required. Minority interest. We owned a 49% controlling interest in the earnings of Grey Wolf through August 2001. The consolidated financial statements include the results of Grey Wolf. The net income attributable to the minority interest in Grey Wolf for the first nine months of 2001 was $1.7 million. As of September 30, 2002, we owned 100% of the outstanding capital stock of Grey Wolf. We obtained the additional interest in Grey Wolf pursuant to a tender offer and subsequent compulsory merger, completed in September 2001. Income taxes. Income taxes decreased to a benefit of $30.3 million for the first nine months of 2002 compared to an expense of $3.7 million for the same period of 2001. This decrease is due to reduced profitability in our operations, primarily as a result of ceiling limitation write-downs and lower commodity prices. There is no current or deferred income tax benefit for the U.S. net losses due the valuation allowance which has been recorded against such benefits. This results in a low consolidated effective tax rate for the nine months ended September 30, 2002. 28 Liquidity and Capital Resources General. The crude oil and natural gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following costs: o the development of existing properties, including drilling and completion costs of wells; o acquisition of interests in crude oil and natural gas properties; and o production and transportation facilities. The amount of capital available to us will affect our ability to service our existing debt obligations and to continue to grow the business through the development of existing properties and the acquisition of new properties. Our lack of liquidity and high debt levels have had a substantial impact on our ability to develop existing properties and acquire new producing properties. Our sources of capital are primarily cash on hand, cash from operating activities, the sale of properties and funding from the Grey Wolf credit facility with Mirant Canada. Our overall liquidity depends heavily on the prevailing prices of crude oil and natural gas and our production volumes of crude oil and natural gas. Significant downturns in commodity prices, such as that experienced in the last nine months of 2001 and the first quarter of 2002, can reduce our cash from operating activities. Although we have hedged a portion of our natural gas and crude oil production and may continue this practice, future crude oil and natural gas price declines would have a material adverse effect on our overall results, and therefore, our liquidity. Furthermore, low crude oil and natural gas prices could affect our ability to raise capital on terms favorable to us. Similarly, our cash flow from operations will decrease if the volume of crude oil and natural gas we produce decreases. Our production volumes will decline as reserves are produced. In addition, we have sold, and intend to continue to sell, certain of our properties. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration, exploitation and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. While we have had some success in pursuing these activities, we have not been able to fully replace the production volumes lost from natural field declines and property sales. Working Capital. At September 30, 2002, we had current assets of $22.6 million and current liabilities of $86.7 million resulting in a working capital deficit of $64.1 million. This compares to a working capital deficit of $5.0 million at December 31, 2001 and working capital deficit of $20.9 million at September 30, 2001. The majority of our current liabilities at September 30, 2002 were current maturities of long-term debt of $63.5 million of our First Lien Notes due March 2003, trade accounts payable of $8.5 million, revenues due third parties of $2.7 million and accrued interest of $9.4 million. Our capital resources and liquidity are affected by the timing of our interest payments of approximately $4.1 million on March 15, 2003, and $11.0 million each May 1, and November 1. As a result of these periodic interest payments on our outstanding debt obligations, our cash balances will decrease dramatically on certain dates during the year. Capital expenditures. Capital expenditures, excluding property divestitures during the first nine months of 2002, were $33.4 million compared to $44.8 million during the same period of 2001. The table below sets forth the components of these capital expenditures on a historical basis for the nine months ended September 30, 2002 and 2001.
Nine months Ended September 30 -------------------------------------------- 2002 2001 ---------------------- --------------------- Expenditure category (in thousands): Acquisitions................................................ $ - $ - Development................................................. 33,240 44,666 Facilities and other........................................ 152 327 --------------- --------------- Total................................................... $ 33,392 $ 44,793 =============== ===============
Investing activities provided $286,000 net during the first nine months of 2002. $33.7 million was provided from the proceeds of property sales during the period. $33.2 million was utilized primarily for the development of crude oil and natural gas properties and other facilities. This compares to using $31.7 million net during the first nine months of 2001, $44.8 million of which was utilized for the development of crude oil and natural gas properties and $15.4 million of which was provided from the sale of properties. As cash flow permits our current budget for capital expenditures for the last three months of 2002 other than acquisition expenditures is approximately $5.1 million. The remaining portion of such expenditures is primarily to be conducted by Grey Wolf, and will be funded by Grey Wolf's cash flow and the Grey Wolf credit facility with Mirant Canada. Additional capital expenditures may be 29 made for acquisition of producing properties if such opportunities arise, but we currently have no agreements, arrangements or undertakings regarding any material acquisitions. We have no material long-term capital commitments and are consequently able to adjust the level of our expenditures as circumstances dictate. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of crude oil and natural gas further decline, our cash flows will decrease which may result in a further reduction of the capital expenditures budget. If we decrease our capital expenditures budget, we may not be able to offset crude oil and natural gas production volumes decreases caused by natural field declines and sales of producing properties. Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: Nine Months Ended September 30, --------------------- 2002 2001 --------------------- (In thousands) --------------------- Net cash (used) provided by operating activities $ (2,820) $ 26,089 Net cash (used) provided by investing activities 286 (31,680) Net cash provided by financing activities ...... 8,605 4,240 -------- -------- Total .......................................... $ 6,071 $ (1,351) ======== ======== Operating activities during the nine months ended September 30, 2002 used $2.8 million cash compared to providing $26.1 million in the same period in 2001. Net loss plus non-cash expense items during 2002 and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $8.6 million for the first nine months of 2002 compared to providing $4.2 million for the same period of 2001. Current Liquidity Requirements. We currently have substantial indebtedness and debt service requirements and we have had recurring net losses in four of the last five years and for the first nine months of 2002. Our loss of approximately $112.8 million during the nine months ended September 30, 2002 was due primarily to non-cash proved property impairments of approximately $116 million resulting from depressed commodity prices. At September 30, 2002, the Company's current liabilities of approximately $86.7 million exceeded current assets of $22.6 million resulting in a working capital deficit of $64.1 million. The Company also had a shareholders' deficit of $138.0 million. The success of our future operations will require us to meet our significant debt obligations and to make substantial capital expenditures for the exploitation, development, exploration and production of crude oil and natural gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties and borrowings under credit facilities and other sources. Recently, our cash flow from operations has been severely impacted by depressed commodity prices and reduced production resulting from sales of producing properties. Our reduced operating cash flow has put significant strain on our liquidity and cash position. At September 30, 2002, we had unrestricted cash of $13.4 million. Our reduced operating cash flow and resulting limited liquidity has also caused us to reduce capital expenditures, including exploration, exploitation and development projects. These measures will limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations and results of operations in the future. Our continued existence as a going concern is dependent upon several current factors including the successful pursuit of financial restructuring alternatives and improvement in commodity prices. We will need additional funds on a timely basis for both the development of our assets and the service of our debt, including the repayment of the $63.5 million in principal amount of the First Lien Notes maturing in March 2003 and the $191 million of the Second Lien Notes and Old Notes maturing in November 2004 - see Note 4. In order to meet the current operating requirements of developing our assets and servicing our debt obligations, we will be required to obtain additional sources of liquidity and capital and/or reduce or reschedule our existing cash requirements including repayment of the First Lien Notes. In order to do so, we are actively pursuing one or more of the following alternatives: o selling all or a portion of our existing assets, including interests in our assets, or subsidiary operations; o negotiating the restructuring and/or refinancing of existing debt; o repaying debt with proceeds from the sale of assets; o exchanging debt for equity; o managing the timing and reducing the scope of our capital expenditures; or o issuing additional debt or equity securities or otherwise raising additional funds. Due to our current debt levels and the restrictions contained in the indentures governing the First Lien Notes, Second Lien Notes and Old Notes, our 30 primary opportunity for immediate additional sources of liquidity and capital will be through the disposition of assets of subsidiary operations and some of the other alternatives discussed above including the restructuring of existing debt. There can be no assurance that any of the above alternatives, or some combination thereof, will be available or, if available, will be on terms acceptable to us or that such efforts will produce enough cash to fund our immediate operating and capital requirements or make timely interest payments and principal payments due on the First Lien Notes, Second Lien Notes and Old Notes. In order to meet our need for current additional funds, the Planning Committee of the Board of Directors is actively pursuing several of the alternatives set forth above. The Planning Committee has engaged an investment banking firm to assist in the formulation of a plan of action for consideration by the Board of Directors. A proposed plan of action expected before December 31, 2002. A refinancing or renegotiation of our existing debt and the sale of additional assets likely will be required for us to meet our current liquidity and capital requirements. Management believes that a successful plan of action can be implemented to provide additional liquidity and capital, but no assurances can be given that the implementation of such a plan of action will result in our being able to continue as a going concern. The September 30, 2002 financial statements do not include any adjustments that might result from the outcome of these going concern uncertainties. See Note 2 to our Consolidated Financial Statements-"Business Conditions and Liquidity Requirements" for more information. Future Capital Resources. We will have three principal sources of liquidity going forward: (i) cash on hand, (ii) cash flow from operations and (iii) sales of properties. In addition, Grey Wolf has additional borrowing capacity under its credit facility with Mirant Canada. The terms of the First Lien Notes indenture, the Second Lien Notes indenture and the Old Notes indenture substantially limit our use of proceeds from sales of properties. Our indentures restrict, among other things, our ability to: o incur additional indebtedness; o incur liens; o pay dividends or make certain other restricted payments; o consummate certain asset sales; o enter into certain transactions with affiliates; o merge or consolidate with any other person; or o sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets. Furthermore, our ability to raise funds through additional indebtedness will be limited because a large portion of our crude oil and natural gas properties and natural gas processing facilities are subject to a first lien or floating charge for the benefit of the holders of the First Lien Notes and a second lien or floating charge for the benefit of the holders of the Second Lien Notes. Finally, our indentures also place restrictions on the use of proceeds from asset sales. Proceeds from asset sales must generally be used for investments in producing properties or related assets. In addition, the indenture for the Second Lien Notes permits using proceeds to make payments under the First Lien Notes. In the event that such proceeds are not used in this manner, we must make an offer to note holders to purchase notes at 100% of the principal amount. Such an offer must be made within 180 days of a property sale. Due to our current debt levels and the restrictions contained in the indentures described above, our best opportunity for additional sources of liquidity and capital will be through the disposition of assets and some of the other alternatives discussed above. We cannot assure you that we will be successful in any of our efforts to improve liquidity or that such efforts will produce enough cash to fund our operating and capital requirements, make our interest payments or to make the principal payments due on our First Lien Notes, Old Notes and Second Lien Notes. In addition, if commodity prices remain at, or fall below their current levels, it will be necessary for us to delay discretionary capital expenditures and seek alternative sources of capital in order to maintain liquidity. Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements: o Long-term debt o Operating leases for office facilities We have no off-balance sheet debt or unrecorded obligations and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of September 30, 2002. 31
Payments due in: ---------------------------------------------------------------------------- Contractual Obligations (dollars in thousands) - --------------------------------------------------------------------------------------------------------------- 2005 and Total 2002 2003 2004 after - ---------------------------------- --------------- -------------- -------------- --------------- -------------- Long-Term Debt (1) $294,699 $ - $63,500 $190,979 $ 40,220 (2) Operating Leases (3) 1,117 132 336 236 413
(1) Includes $63.5 million of the First Lien Notes, $191.0 million of the Old Notes and Second Lien Notes and $40.2 million under the Grey Wolf Facility. (2) The Grey Wolf credit facility does not have scheduled repayments of principal prior to its maturing in 2007. Instead, Grey Wolf is required to pay its net cash flow on a monthly basis to Mirant Canada. We have included the entire amount outstanding under the Grey Wolf Facility at September 30, 2002 ($40.2 million) although we will be making payments prior to 2007. For more information on the Grey Wolf credit facility, you should read the description under "Debt - Grey Wolf Facility." (3) Office lease obligations. Other obligations. We make and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of crude oil and natural gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments to Mirant Americas and borrowings under our bank credit facilities and other sources. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion. As cash flow permits our capital expenditure budget for the remainder of 2002 for existing operations and leaseholds is approximately $5.1 million. Indebtedness. Old Notes. On November 14, 1996, we consummated the offering of $215.0 million of our 11.5% Senior Notes due 2004, Series A, which were exchanged for the Series B Notes in February 1997. On January 27, 1998, we completed the sale of $60.0 million of our 11.5% Senior Notes due 2004, Series C. The Series B Notes and the Series C Notes were subsequently combined into $275.0 million in principal amount of the Old Notes in June 1998. In December 1999, Abraxas and Canadian Abraxas completed an exchange offer which reduced the amount of outstanding Old Notes to $801,000. See the description of the Second Lien Notes below for more information. Interest on the Old Notes is payable semi-annually in arrears on May 1 and November 1 of each year at the rate of 11.5% per annum. The Old Notes are redeemable at our option, in whole or in part, at 100% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on November 1 of 2002 and thereafter. The Old Notes are joint and several obligations of Abraxas and Canadian Abraxas and rank pari passu in right of payment to all existing and future unsubordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes rank senior in right of payment to all future subordinated indebtedness of Abraxas and Canadian Abraxas. The Old Notes are, however, effectively subordinated to the First Lien Notes to the extent of the value of the collateral securing the First Lien Notes and to the Second Lien Notes to the extent of the value of the collateral securing the Second Lien Notes. The Old Notes are unconditionally guaranteed, on a senior basis by Sandia and Wamsutter, each of which is a wholly-owned subsidiary of Abraxas. The guarantees are general unsecured obligations of Sandia and Wamsutter and rank pari passu in right of payment to all unsubordinated indebtedness of Sandia and Wamsutter and senior in right of payment to all subordinated indebtedness of Sandia and Wamsutter. The guarantees are effectively subordinated to the First Lien Notes and the Second Lien Notes to the extent of the value of the collateral securing the First Lien Notes and the Second Lien Notes. Upon a Change of Control, as defined in the Old Notes Indenture, each holder of the Old Notes will have the right to require us to repurchase all or a portion of such holder's Old Notes at a redemption price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. In addition, we will be obligated to offer to repurchase the Old Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase in the event of certain asset sales. First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5 million of the First Lien Notes. Interest on the First Lien Notes is payable 32 semi-annually in arrears on March 15 and September 15, commencing September 15, 1999. Beginning March 15, 2002, the First Lien Notes are redeemable, in whole or in part, at the option of Abraxas at the par value price, plus accrued and unpaid interest to the date of redemption. The First Lien Notes are senior indebtedness of Abraxas secured by a first lien on substantially all of the crude oil and natural gas properties of Abraxas and the shares of Grey Wolf owned by Abraxas. The First Lien Notes are unconditionally guaranteed on a senior basis, jointly and severally, by Canadian Abraxas, Sandia and Wamsutter, wholly-owned subsidiaries of Abraxas (the "Restricted Subsidiaries"). The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors and the shares of Grey Wolf owned by Abraxas and Canadian Abraxas. Upon a Change of Control, as defined in the First Lien Notes Indenture, each holder of the First Lien Notes will have the right to require Abraxas to repurchase such holder's First Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas will be obligated to offer to repurchase the First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales. The First Lien Notes indenture contains certain covenants that limit the ability of Abraxas and certain of its subsidiaries, including the guarantors of the First Lien Notes to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas. The First Lien Notes indenture provides, among other things, that Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas or any other Restricted Subsidiary except for such encumbrances or restrictions existing under or by reason of: (1) applicable law; (2) the First Lien Notes indenture; (3) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries; (4) any instrument governing indebtedness assumed by us in an acquisition, which encumbrance or restriction is not applicable to such Restricted Subsidiary or the properties or assets of such subsidiary other than the entity or the properties or assets of the entity so acquired; (5) agreements existing on the Issue Date (as defined in the First Lien Notes indenture) to the extent and in the manner such agreements were in effect on the Issue Date; (6) customary restrictions with respect to subsidiaries of Abraxas pursuant to an agreement that has been entered into for the sale or disposition of capital stock or assets of such Restricted Subsidiary to be consummated in accordance with the terms of the First Lien Notes indenture or any Security Documents (as defined in the First Lien Notes indenture) solely in respect of the assets or capital stock to be sold or disposed of; (7) any instrument governing certain liens permitted by the First Lien Notes indenture, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such lien; or (8) an agreement governing indebtedness incurred to refinance the indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (2), (4) or (5) above; provided, however, that the provisions relating to such encumbrance or restriction contained in any such refinancing indebtedness are no less favorable to the holders of the First Lien Notes in any material respect as determined by the Board of Directors of Abraxas in their reasonable and good faith judgment that the provisions relating to such encumbrance or restriction contained in the applicable agreement referred to in such clause (2), (4) or (5) and do not extend to or cover any new or additional property or assets and, with respect to newly created liens, (A) such liens are expressly 33 junior to the liens securing the First Lien Notes, (B) the refinancing results in an improvement on a pro forma basis in Abraxas' Consolidated EBITDA Coverage Ratio (as defined in the First Lien Notes indenture) and (C) the instruments creating such liens expressly subject the foreclosure rights of the holders of the refinanced indebtedness to a stand-still of not less than 179 days. Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas consummated an exchange offer whereby $269,699,000 of the Old Notes were exchanged for $188,778,000 of the Second Lien Notes, and 16,078,990 shares of Abraxas common stock and contingent value rights. An additional $5,000,000 of the Second Lien Notes were issued in payment of fees and expenses. Interest on the Second Lien Notes is payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2000. We deferred an interest payment of approximately $11 million dollars, related to Old Notes and the Second Lien Notes, due on May 1, 2002. We had a 30-day grace period in which to make this $11 million payment before an "event of default" occurred. The interest payment was made on May 23, 2002, prior to the expiration of the grace period. The Second Lien Notes are redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas at 100% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on December 1 of 2002 and thereafter. The Second Lien Notes are senior indebtedness of Abraxas and Canadian Abraxas and are secured by a second lien on substantially all of the crude oil and natural gas properties of Abraxas and Canadian Abraxas and the shares of Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are unconditionally guaranteed on a senior basis, jointly and severally, by Sandia and Wamsutter. The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors. The Second Lien Notes are, however, effectively subordinated to the First Lien Notes and related guarantees to the extent the value of the collateral securing the Second Lien Notes and related guarantees and the First Lien Notes and related guarantees is insufficient to pay both the Second Lien Notes and the First Lien Notes. Upon a Change of Control, as defined in the Second Lien Notes Indenture, each holder of the Second Lien Notes will have the right to require Abraxas and Canadian Abraxas to repurchase such holder's Second Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas will be obligated to offer to repurchase the Second Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales. The Second Lien Notes indenture contains certain covenants that limit the ability of Abraxas and Canadian Abraxas and certain of their subsidiaries, including the guarantors of the Second Lien Notes (the "Restricted Subsidiaries") to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas or Canadian Abraxas. The Second Lien Notes indenture provides, among other things, that Abraxas and Canadian Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas, Canadian Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary except for such encumbrances or restrictions existing under or by reason of: (1) applicable law; (2) the Old Notes indenture, the First Lien Notes indenture, or the Second Lien Notes indenture; (3) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries; (4) any instrument governing indebtedness assumed by us in an acquisition, which encumbrance or restriction is not applicable to such Restricted Subsidiary or the properties or assets of such subsidiary other than the entity or the properties or assets of the entity so acquired; 34 (5) agreements existing on the Issue Date (as defined in the Second Lien Notes indenture) to the extent and in the manner such agreements were in effect on the Issue Date; (6) customary restrictions with respect to subsidiaries of Abraxas and Canadian Abraxas pursuant to an agreement that has been entered into for the sale or disposition of capital stock or assets of such Restricted Subsidiary to be consummated in accordance with the terms of the Second Lien Notes solely in respect of the assets or capital stock to be sold or disposed of; (7) any instrument governing certain liens permitted by the Second Lien Notes indenture, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such lien; or (8) an agreement governing indebtedness incurred to refinance the indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (2), (4) or (5) above; provided, however, that the provisions relating to such encumbrance or restriction contained in any such refinancing indebtedness are no less favorable to the holders of the Second Lien Notes in any material respect as determined by the Board of Directors of Abraxas in their reasonable and good faith judgment that the provisions relating to such encumbrance or restriction contained in the applicable agreement referred to in such clause (2), (4) or (5). Grey Wolf Facility. General. On December 20, 2001, Grey Wolf entered into a credit facility with Mirant Canada. The Grey Wolf credit facility established a revolving line of credit with a commitment amount of CDN $150 million, (approximately US $96 million). Subject to certain restrictions, the borrowing base may be reduced in the discretion of Mirant Canada upon 30 days written notice. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date of the credit facility is December 20, 2007. The applicable interest rate charged on the outstanding balance under the Grey Wolf Facility is 9.5%. Any amounts in default under the facility will accrue interest at 15%. The Grey Wolf credit facility is non-recourse to Abraxas and its properties, other than Grey Wolf properties, and Abraxas has no additional direct obligations to Mirant Canada under the facility. Principal Payments. Prior to maturity, Grey Wolf is required to make principal payments under the Grey Wolf credit facility as follows: (i) on the date of the sale of any of its producing properties, Grey Wolf is required to make a payment equal to the amount of the net sales proceeds; (ii) on a monthly basis, Grey Wolf is required to make a payment equal to its net cash flow for the month prior to the date of the payment; and (iii) on the date of any reduction in the commitment amount becomes effective, Grey Wolf must repay all amounts over the commitment amount so reduced. Under the Grey Wolf credit facility, "net cash flow" generally means the amount of proceeds received by Grey Wolf from the sale of hydrocarbons less taxes, royalty and similar payments (including overriding royalty interest payments made to Mirant Canada), interest payments made to Mirant Canada and operating and other expenses including approved capital and G&A expenses. Grey Wolf may also make pre-payments at any time after December 20, 2002 with no pre-payment penalty. The Grey Wolf credit facility matures in 2007. We treat the Grey Wolf credit facility as a revolving line of credit since, under ordinary circumstances, the lender is paid on a net cash flow basis. It is anticipated that Grey Wolf will be a net borrower for the next several years due to a large number of exploration and exploitation projects and the associated capital needs to complete the projects. Security. Obligations under the Grey Wolf credit facility are secured by a security interest in substantially all of Grey Wolf's assets, including, without limitation, working capital interests in producing properties and related assets owned by Grey Wolf. None of Abraxas' assets are subject to a security interest under the Grey Wolf credit facility. Covenants. The Grey Wolf credit facility contains a number of covenants that, among other things, restrict the ability of Grey Wolf to (i) enter into new business areas, (ii) incur additional indebtedness, (iii) create or permit 35 to be created any liens on any of its properties, (iv) make certain payments, dividends and distributions, (v) make any unapproved capital expenditures, (vi) sell any of its accounts receivable, (vii) enter into any unapproved leasing arrangements, (viii) enter into any take-or-pay contracts, (ix) liquidate, dissolve, consolidate with or merge into any other entity, (x) dispose of its assets, (xi) abandon any property subject to Mirant Canada's security interest, (xii) modify any of its operating agreements, (xiii) enter into any unapproved hedging agreements, and (xiv) enter into any new agreements affecting existing agreements relating to or affecting properties subject to Mirant Canada's security interests. In addition, Grey Wolf is required to submit a quarterly development plan for Mirant Canada's approval and Grey Wolf must comply with specified financial ratios and tests, including a minimum collateral coverage ratio. Grey Wolf was in compliance with these covenants at September 30, 2002. Events of Default. The Grey Wolf credit facility contains customary events of default, including nonpayment of principal or interest, violations of covenants, inaccuracy of representations or warranties in any material respect, cross default and cross acceleration to certain other indebtedness, bankruptcy, material judgments and liabilities, change of control and any material adverse change in the financial condition of Grey Wolf. Overriding Royalty Interests. As a condition to the Grey Wolf credit facility, Grey Wolf has granted two overriding royalty interests to Mirant Canada, each in the amount of 2.5% of the revenues received by Grey Wolf from crude oil and natural gas sales from all of its properties. These overriding royalty interests resulted in the recording of a $2.5 million discount on the Grey Wolf Facility borrowings at December 31, 2001. Hedging Activities. Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. See Hedging Sensitivity in Item 3 for further information. Net Operating Loss Carryforwards. At December 31, 2001 we had, subject to the limitation discussed below, $115,900,000 of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2002 through 2021 if not utilized. At December 31, 2001, we had approximately $6,700,000 of net operating loss carryforwards for Canadian tax purposes. These carryforwards will expire from 2002 through 2008 if not utilized. As a result of the acquisition of certain partnership interests and crude oil and natural gas properties in 1990 and 1991, an ownership change under Section 382 occurred in December 1991. Accordingly, it is expected that the use of the U.S. net operating loss carryforwards generated prior to December 31, 1991 of $3,203,000 will be limited to approximately $235,000 per year. During 1992, we acquired 100% of the common stock of an unrelated corporation. The use of net operating loss carryforwards of the acquired corporation of $257,000 acquired in the acquisition are limited to approximately $115,000 per year. As a result of the issuance of additional shares of common stock for acquisitions and sales of common stock, an additional ownership change under Section 382 occurred in October 1993. Accordingly, it is expected that the use of all U.S. net operating loss carryforwards generated through October 1993 (including those subject to the 1991 and 1992 ownership changes discussed above) of $6,590,000 will be limited as described above and in the following paragraph. An ownership change under Section 382 occurred in December 1999, following the issuance of additional shares, as described in Note 5. It is expected that the annual use of U.S. net operating loss carryforwards subject to this Section 382 limitation will be limited to approximately $363,000, subject to the lower limitations described above. Future changes in ownership may further limit the use of our carryforwards. In 2000 assets with built in gains were sold, increasing the Section 382 limitation for 2001 by approximately $31,000,000. The annual Section 382 limitation may be increased during any year, within 5 years of a change in ownership, in which built-in gains that existed on the date of the change in ownership are recognized. In addition to the Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, we have established a valuation allowance of $39,670,000 and $62,496,000 for deferred tax assets at December 31, 2001 and September 30, 2002 respectively. 36 Item 3. Quantitative and Qualitative Disclosures about Market Risk. Commodity Price Risk Our exposure to market risk rests primarily with the volatile nature of crude oil, natural gas and natural gas liquids prices. We manage crude oil and natural gas prices through the periodic use of commodity price hedging agreements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources". Assuming the production levels we attained during the nine months ended September 30, 2002, a 10% decline in crude oil, natural gas and natural gas liquids prices would have reduced our operating revenue, cash flow and net income (loss) by approximately $1.4 million for the nine months ended September 30, 2002. Hedging Sensitivity On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, we use only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Other Comprehensive Income/Loss, a component of Stockholder's Equity, to the extent that the hedge is effective. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in accumulated Other Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective, remain unchanged until the related production is delivered. If we determine that it is probable that a hedged transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. Gains and losses on hedging instruments related to accumulated Other Comprehensive Income and adjustments to carrying amounts on hedged production are included in natural gas or crude oil production revenue in the period that the related production is delivered. The following table sets forth our hedging position as of September 30, 2002.
Time Period Notional Quantities Price Fair Value - ---------------------------------------- ------------------------------ ------------------------------ ---------------- October 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $2.60-$2.95 $(0.6) million gas or 1,000 Bbl/day of natural gas or crude oil $18.90 Crude oil
On January 1, 2001, in accordance with the transition provisions of SFAS 133, we recorded $31.0 million, net of tax, in other comprehensive loss representing the cumulative effect of an accounting change to recognize the fair value of cash flow derivatives. We recorded cash flow hedge derivative liabilities of $38.2 million on that date and a deferred tax asset of $7.2 million. During the first nine months of 2002 the fair value of outstanding liabilities increased by $2.5 million. For the three months and nine months ended September 30, 2002 the ineffective portion of the cash flow hedges were not material. As of September 30, 2002, $0.5 million of deferred net losses on derivative instruments were recorded in Other Comprehensive Income/Loss, which is expected to be reclassified to earnings upon the expiration of the hedge in October 2002. All hedge transactions are subject to our risk management policy, which has been approved by the Board of Directors. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. 37 The fair value of the hedging instrument was determined based on the base price of the hedged item and NYMEX forward price quotes. As of September 30, 2002, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of $64,000 and a commodity price decrease of 10% would have resulted in a favorable change in fair market value of $64,000. Interest rate risk At September 30, 2002, substantially all of our long-term debt is at fixed interest rates and not subject to fluctuations in market rates. Foreign currency Our Canadian operations are measured in the local currency of Canada. As a result, our financial results could be affected by changes in foreign currency exchange rates or weak economic conditions in the foreign markets. Canadian operations reported a pre tax loss of $94.4 million for the nine months ended September 30, 2002. It is estimated that a 5% change in the value of the U.S. dollar to the Canadian dollar would have changed our pre tax income by approximately $4.7 million. We do not maintain any derivative instruments to mitigate the exposure to translation risk. However, this does not preclude the adoption of specific hedging strategies in the future. New Accounting Standards In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires an asset retirement obligation to be recorded at fair value during the period incurred and an equal amount recorded as an increase in the value of the related long-lived asset. The capitalized cost is depreciated over the useful life of the asset and the obligation is accreted to its present value each period. SFAS No. 143 is effective for us beginning January 1, 2003. We are currently evaluating the impact the standard will have on our future results of operations and financial condition. Effective January 1, 2002, we adopted SFAS No. 144 " Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 retains the requirement to recognize an impairment loss only where the carrying value of a long-lived asset is not recoverable from its undiscounted cash flows and to measure such loss as the difference between the carrying amount and fair value of the asset. SFAS No. 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. This new standard had no impact on the our consolidated financial statements during the first nine months of 2002. In April 2002, the FASB issued SFAS No. 145, "Recission of FASB No. 4, 44, and 64, Amendments of FASB Statement No. 13 and Technical Corrections." SFAS No. 145 clarifies guidance related to the reporting of gains and losses from extinguishment of debt and resolves inconsistencies related to the required accounting treatment of certain lease modifications. SFAS No. 145 also amends other existing pronouncements to make various technical corrections, clarify meanings or describe their applicability under changed conditions. The provisions relating to the reporting of gains and losses from extinguishment of debt become effective for us beginning January 1, 2003 with earlier adoption encouraged. All other provisions of this standard have been effective for the us as of May 15, 2002 and did not have a significant impact on our financial condition or results of operations. In June 2002, the FASB issued SFAS No. 146, "Accounting for Cost Associated with Exit or Disposal Activities." SFAS No. 146 requires costs associated with exit of disposal activities to be recognized when they are incurred rather than at the date of commitment to an exit or disposal plan. SFAS No. 146 is effective for us beginning January 1, 2003. We are currently evaluating the impact the standard will have on its results of operations and financial condition. The American Institute of Certified Public Accountants has issued an Exposure Draft for a Proposed Statement of Position, " Accounting for Certain Costs and Activities Related to Property, Plant and Equipment" which would require major maintenance activities to be expensed as costs are incurred. We are currently evaluating the impact on our results of operations and financial condition if this Proposed Statement of Position is adopted in its current form. Disclosure Regarding Forward-Looking Information This report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements other than statements of historical facts included in this report 38 regarding our financial position, business strategy, budgets and plans and objectives of management for future operations are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations ("Cautionary Statements") are disclosed under "Risk Factors" in our Annual Report on Form 10-K which is incorporated by reference herein and this report. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the Cautionary Statements. Item 4. Controls and Procedures. Within the 90 days prior to the date of this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas' "disclosure controls and procedures" (as defined in the Securities Exchange Act of 1934 Rules 13a-14(c) and 15d-14(c)) and have concluded that the disclosure controls and procedures were adequate and designed to ensure that material information relating to Abraxas and our consolidated subsidiaries which is required to be included in our periodic Securities and Exchange Commission filings would be made know to them by others within those entities. There were no significant changes in our internal controls or in other factors that could significantly affect our disclosure controls and procedures subsequent to the date of this evaluation, nor any significant deficiencies or material weaknesses in such disclosure controls and procedures requiring corrective actions. ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES PART II OTHER INFORMATION Item 1. Legal Proceedings None Item 2. Changes in Securities None Item 3. Defaults Upon Senior Securities None Item 4. Submission of Matters to a Vote of Security Holders None Item 5. Other Information None Item 6. Exhibits and Reports on Form 8-K (a) Exhibits None (b) Reports on Form 8-K: 1. Current Report on Form 8-K filed on July 9, 2002. Acquisition or Disposition of Assets, announcing the Company's divestiture of properties in Alberta, Canada and South Texas. 2. Current Report on Form 8-K/A filed on August 8, 2002 to amend the Form 8-K filed on July 9, 2002, to include the pro-forma financial statements relating to the property divestitures. 39 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES 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. ABRAXAS PETROLEUM CORPORATION (Registrant) Date: November 14, 2002 By:/s/Robert L.G. Watson -------------------- ------------------------------- ROBERT L.G. WATSON, President and Chief Executive Officer Date: November 14, 2002 By:/s/Chris Williford ------------------- ------------------------------- CHRIS WILLIFORD, Executive Vice President and Principal Accounting Officer 40 CERTIFICATIONS I Robert L.G. Watson, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Abraxas Petroleum Corporation; 2. Based on my knowledge, this quarterly report does not contain untrue statements 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 presents 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 officer 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) designated 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) evaluate 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 officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the 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 officer 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. November 14, 2002 /s/ Robert L.G. Watson - ----------------------- Robert L.G. Watson President, Chief Executive Officer and Chairman of the Board 41 CERTIFICATIONS I Chris Williford, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Abraxas Petroleum Corporation; 2. Based on my knowledge, this quarterly report does not contain untrue statements 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 presents 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 officer 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. designated 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. evaluate 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 officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the 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 officer 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 November 14, 2002 /s/ Chris Williford - ------------------- Chris Williford Executive Vice President and Principal Accounting Officer -----END PRIVACY-ENHANCED MESSAGE-----