10-Q 1 abp10q102.txt UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) FORM10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended March 31, 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 May 14, 2002 was: Class Shares Outstanding Common Stock, $.01 Par Value 29,979,397 1 of 35 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES FORM 10 - Q INDEX PART I FINANCIAL INFORMATION ITEM 1 - Financial Statements (Unaudited) Consolidated Balance Sheets - March 31, 2002 and December 31, 2001................................3 Consolidated Statements of Operations - Three Months Ended March 31, 2002 and 2001...........5 Consolidated Statement of Stockholders Equity (Deficit) March 31, 2002 and December 31, 2001.................6 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2002 and 2001...........7 Notes to Consolidated Financial Statements....................8 ITEM 2 - Managements Discussion and Analysis of Financial Condition and Results of Operations.................20 ITEM 3 - Quantitative and Qualitative Disclosure about Market Risks...32 PART II OTHER INFORMATION ITEM 1 - Legal proceedings 34 ITEM 2 - Changes in Securities.............................................34 ITEM 3 - Defaults Upon Senior Securities...................................34 ITEM 4 - Submission of Matters to a Vote of Security Holders...............34 ITEM 5 - Other Information 34 ITEM 6 - Exhibits and Reports on Form 8-K..................................34 Signatures ................................................35 2
Abraxas Petroleum Corporation and Subsidiaries Part 1- Financial Information Item 1 - Financial Statements Consolidated Balance Sheets March 31, December 31, 2002 2001 (Unaudited) ------------------------ (In Thousands) Assets: Current assets: Cash ....................................................... $ 3,851 $ 7,605 Accounts receivable, less allowances for doubtful accounts: Joint owners ........................................ 2,884 2,785 Oil and gas production .............................. 3,824 4,758 Other ............................................... 548 504 -------- -------- 7,256 8,047 Equipment inventory ......................................... 1,160 1,251 Other current assets ........................................ 1,050 443 -------- -------- Total current assets ...................................... 13,317 17,346 Property and equipment: Oil and gas properties, full cost method of accounting: Proved .................................................. 505,195 486,098 Unproved, not subject to amortization ................... 5,937 10,626 Other property and equipment ............................... 69,962 67,632 -------- -------- Total .............................................. 581,094 564,356 Less accumulated depreciation, depletion, and amortization .......................................... 289,028 282,462 -------- -------- Total property and equipment - net ...................... 292,066 281,894 Deferred financing fees, net of accumulated amortization of $9,095 and $8,668 at March 31, 2002 and December 31, 2001, respectively ................................................ 3,464 3,928 Other assets .................................................. 447 448 -------- -------- Total assets ................................................ $309,294 $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) March 31, December 31, 2002 2001 (Unaudited) ----------------------- (In Thousands) Liabilities and Shareholder's Equity (Deficit) Current liabilities: Accounts payable ......................................... $ 17,805 $ 10,542 Oil and gas production payable ........................... 2,307 3,596 Accrued interest ......................................... 9,378 6,013 Other accrued expenses ................................... 1,521 1,116 Hedge liability .......................................... 3,256 658 Current maturities of long-term debt ..................... 63,911 415 --------- --------- Total current liabilities ...................... 98,178 22,340 Long-term debt ............................................. 227,103 285,184 Deferred income taxes ...................................... 19,742 20,621 Future site restoration .................................... 3,997 4,056 Shareholders' equity (deficit): Common Stock, par value $.01 per share- Authorized 200,000,000 shares; issued, 30,145,280 at March 31, 2002 and December 31, 2001....... 301 301 Additional paid-in capital .............................. 136,733 136,733 Accumulated deficit ...................................... (159,793) (151,094) Treasury stock, at cost, 165,883 shares .................. (964) (964) Accumulated other comprehensive loss ..................... (16,003) (13,561) --------- --------- Total shareholders' deficit .......................... (39,726) (28,585) --------- --------- Total liabilities and shareholders' equity (deficit)....... $ 309,294 $ 303,616 ========= =========
See accompanying notes to consolidated financial statements 4
Abraxas Petroleum Corporation and Subsidiaries Consolidated Statements of Operations (Unaudited) Three Months Ended March 31, ----------------------- 2002 2001 ----------------------- (In thousands except per share data) Revenue: Oil and gas production revenues ........................... $ 10,886 $ 28,249 Gas processing revenue .................................... 670 436 Rig revenues .............................................. 151 183 Other ..................................................... 100 218 -------- -------- 11,807 29,086 Operating costs and expenses: Lease operating and production taxes ...................... 3,909 4,859 Depreciation, depletion and amortization .................. 6,814 8,841 Rig operations ............................................ 121 153 General and administrative ................................ 1,698 2,109 General and administrative (Stock-based Compensation) ..... -- 931 -------- -------- 12,542 16,893 -------- -------- Operating Income (Loss) ...................................... (735) 12,193 Other (income) expense Interest income ........................................... (16) (33) Interest expense .......................................... . 7,781 8,413 Amortization of deferred financing fees ................... 455 427 Other ..................................................... -- 16 -------- -------- 8,807 8,236 -------- -------- Income (Loss) from operations before taxes ................... (9,542) 3,957 Income tax expense (benefit) ................................. (843) 2,776 Minority interest in income of consolidated foreign subsidiary -- (926) -------- -------- Net Income (Loss) ............................................ $ (8,699) $ 255 ======== ======== Earnings per share: Net income per common share - basic ...................... $ (0.29) $ .01 ======== ======== Net income per common - diluted .......................... $ (0.29) $ .01 ======== ========
See accompanying notes to consolidated financial statements 5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) (In thousands except share amounts) Accumulated Common Stock Treasury Stock Additional Other -------------------- ---------- ----------- Paid-In Accumulated Comprehensive Shares Amount Shares Amount Capital Deficit Income(Loss) Total ----------- ---------- -------- --------- ----------- ----------- ----------- ---------- Balance at December 31, 2001.............. 30,145,280 $ 301 165,883 $ (964) $ 136,733 $ (151,094) $(13,561) $ (28,585) Comprehensive income (loss) - Note 8 Net loss................................ - - - - - (8,699) - (8,699) Other comprehensive income: Hedge loss............................ - - - - - - (2,075) (2,075) Foreign currency translation adjustment........................... - - - - - - (367) (367) --------- Comprehensive income (loss)........ - - - - - - - (11,141) ----------- --------- ---------- -------- ------------- ----------- ---------- --------- Balance at March 31, 2002................. 30,145,280 $ 301 165,883 $ (964) $ 136,733 $ (159,793) (16,003) $ (39,726) =========== ========= ========== ======== ============= =========== ========== =========
See accompanying notes to consolidated financial statements 6
Abraxas Petroleum Corporation and Subsidiaries Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, ----------------------- 2002 2001 ------------ ---------- (In thousands) Operating Activities Net income (loss) ................................................... $ (8,699) $ 255 Adjustments to reconcile net income to net cash provided by operating activities: Minority interest in income of foreign subsidiary .................. -- 926 Depreciation, depletion, and amortization .......................... 6,814 8,841 Deferred income tax (benefit) expense .............................. (843) 2,695 Amortization of deferred financing fees ............................ 427 455 Amortization of debt discount ...................................... 113 Stock-based compensation ........................................... -- 931 Changes in operating assets and liabilities: Accounts receivable ............................................ 1,099 6,585 Equipment inventory ............................................ 91 44 Other .......................................................... (87) (54) Accounts payable and accrued expenses .......................... 9,367 (3,254) -------- -------- Net cash provided by operating activities ........................... 8,282 17,424 -------- -------- Investing Activities Capital expenditures, including purchases and development of properties ..................................................... (17,408) (17,861) Proceeds from sale of oil and gas producing properties .............. -- 44 -------- -------- Net cash used in investing activities ............................... $(17,408) $(17,817) -------- -------- Financing Activities Proceeds from long-term borrowings .................................. 6,096 3,320 Payments on long-term borrowings .................................... (719) (2,827) Deferred financing fees ............................................. (8) Exercise of stock options ........................................... -- 10 -------- -------- Net cash provided by financing activities ........................... 5,377 495 -------- -------- Effect of exchange rate changes on cash ............................. (5) (38) -------- -------- Increase (decrease) in cash ......................................... (3,754) 64 Cash, at beginning of period ........................................ 7,605 2,004 -------- -------- Cash, at end of period .............................................. $ 3,851 $ 2,068 ======== ======== Supplemental disclosures of cash flow information: Interest paid ....................................................... $ 4,935 $ 4,414 ======== ========
See accompanying notes to consolidated financial statements 7 Abraxas Petroleum Corporation and Subsidiaries Notes to Consolidated Financial Statements (Unaudited) March 31, 2002 Note 1. Basis of Presentation Theaccounting policies followed by Abraxas Petroleum Corporation and its subsidiaries (the "Company" or "Abraxas") are set forth in the notes to the Company's audited 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 months ended March 31, 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. Liquidity At March 31, 2002 the Company's current liabilities of approximately $98.2 million exceeded its current assets of $13.3 million. Included in current liabilities are trade payables of $17.8 million, revenues due third parties of $2.3 million, accrued interest of $9.4 million and current maturities of long-term debt of $63.9 million. Current maturities of long-term debt includes $63.5 million of the Second Lien Notes, due March 2003. Included in the $9.4 million of accrued interest is $ 9.1 million of the $ 11.0 million due May 1, 2002 on the Old Notes and the Second Lien Notes, which payment was not made. The Company has a 30-day grace period in which to make this $11.0 million payment before an "event of default" occurs. The total interest due is $11.0 million. Should such 30-day period expire without the interest payment being made, the event of default would also result in an event of default under the indenture related to the First Lien Notes. Such event of default would allow for the holders of the Old Notes, the First Lien Notes and the Second Lien Notes to declare the entire principal and unpaid interest on all of the Company's outstanding notes ($254.5 million) to be due and payable. The Company has four principal sources of liquidity going forward: (i) cash on hand, (ii) cash flow from operations, (iii) a production payment related to certain U.S. properties, and (iv) sale of assets and property. Grey Wolf also has availability under its financing agreement entered into in December 2001. The First Lien Notes indenture, the Second Lien Notes indenture and the Old Notes indenture substantially limit the use of proceeds from asset sales. Most of the Company's capital expenditures are discretionary and can be delayed to maintain current liquidity. In December 2001, the Company's wholly owned subsidiary, Grey Wolf, entered into a financing agreement ("Grey Wolf Facility") with Mirant Canada Energy Capital, Ltd. ("Mirant Canada") for US $96 million (CDN $150 million) senior secured facility, which is non-recourse to Abraxas. Initial proceeds from this facility of approximately US $25 million were used to retire Grey Wolf's existing bank debt and for general corporate purposes. Up to US $71 million is available to finance the drilling of wells and related activities in the Grey Wolf development plan, as anticipated over the next two years. 8 The Company's wholly owned Canadian subsidiaries, Canadian Abraxas and Grey Wolf, entered into a definitive Purchase and Sale Agreement related to the sale of their interest in a natural gas plant and the associated reserves. The sale, effective March 1, 2002, is expected to close on or about May 23, 2002 with estimated net proceeds of US $21.5 million. The Company has recently engaged Randall & Dewey, Inc. to explore a potential sale of certain properties located in Texas. The data room was opened in March of 2002, with bids due in the second quarter of 2002. There are no definitive agreements related to this potential sale and there can be no assurance that any sale will occur or, if it does, the sales price that would be received. If all of the potential sales are ultimately closed, we anticipate aggregate proceeds in the range of $50 million to $100 million. The Company will need additional funds in the future 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 the First Lien Notes maturing in March 2003 and the $191 million of the Second Lien Notes and Old Notes maturing in November 2004. In order to meet the goals of developing its assets and servicing its debt obligations, the Company will be required to obtain additional sources of capital and/or reduce or reschedule its existing cash requirements. In order to do so, the Company may pursue one or more of the following alternatives: o refinancing 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; o issuing debt or equity securities or otherwise raising additional funds; or o selling all or a portion of its existing assets, including interests in its assets. The Company has implemented a number of measures to conserve its cash resources, including postponement of certain exploration and development projects. However, while these measures will help conserve the Company's cash resources in the near term, they will also limit the Company's ability to replenish its depleting reserves, which could negatively impact the Company's operating cash flow and results of operations in the future. Due to our current debt levels and the restrictions contained in the indentures, our best opportunity for additional sources of 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. While the availability of capital resources and future liquidity cannot be predicted with certainty and is dependent upon a number of factors including factors outside of management's control, management believes that the net cash flow from operations plus cash on hand, cash available under other arrangements and the proceeds from the sale of properties will be adequate to fund operations and planned capital expenditures for the foreseeable future, and the repayment of the $63.5 million in principal amount of the First Lien Notes maturing in March 2003. Note 3. Long-Term Debt
Long-term debt consists of the following: March 31 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 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). Secured by the assets of Grey Wolf and non-recourse to Abraxas, net of US $2.1 and $2.3 million discount at March 31, 2002 and December 31, 2001, respectively.................................. 29,112 22,944 Production Payment ................................................... 7,423 8,176 ----------------- ----------------- 291,014 285,599 Less current maturities ............................................... 63,911 415 ----------------- ----------------- $ 227,103 $ 285,184 ================= =================
9 Old Notes. On November 14, 1996, the Company consummated the offering of $215.0 million of it's 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. 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 the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on November 1 of the years set forth below: Year Percentage ---- ---------- 2001................................. 102.875% 2002 and thereafter.................. 100.000% 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"), a wholly owned subsidiary of the Company. The guarantee is a general unsecured obligation of Sandia and ranks pari passu in right of payment to all unsubordinated indebtedness of Sandia and senior in right of payment to all subordinated indebtedness of Sandia. The guarantee is 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. 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 10 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 the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on December 1 of the years set forth below: Year Percentage ----- ---------- 2001.......................................... 102.875% 2002 and thereafter........................... 100.000% 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 Grey Wolf Facility 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. 11 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 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. 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. 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. 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. 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. 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. 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 interest result in the recording of a $2.3 million discount on the Grey Wolf Facility borrowings at December 31, 2001. 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 has an aggregate total availability of up to $50 million at 15% interest. The Production Payment relates to a portion of the production from several natural gas wells in South Texas. As of March 31, 2002, the Company had received $22.1 million under this agreement. The outstanding balance as of March 31, 2002 is $7.4 million. Note 4. Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share: 12
Three Months Ended March 31, ------------------------------- 2002 2001 --------------- --------------- Numerator: Numerator for basic and diluted earnings per share - income (in thousands) ......................................................... $ (8,699) $ 255 Denominator: Denominator for basic earnings per share - weighted-average shares .... 29,979,397 22,595,969 Effect of dilutive securities: Stock options, Warrants and CVRs ................................... -- 4,681,387 ------------ ------------ Dilutive potential common shares Denominator for diluted earnings per share - adjusted weighted-average shares and assumed Conversions ..................................... 29,979,397 27,277,356 Basic earnings per share: ............................................... $ (0.29) $ 0.01 ============ ============ Diluted earnings per share: ............................................. $ (0.29) $ 0.01 ============ ============
For the three months ended March 31, 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 45,982 shares for the three months ended March 31, 2002. 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 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 5. 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 March 31, 2002 and December 31, 2001 and the related consolidating statements of operations for the three months ended March 31, 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.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet March 31, 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 .................................... $ (220) $ 1,215 $ 2,856 $ - $ 3,851 Accounts receivable, less allowance for doubtful accounts...................... 15,642 777 12,320 (21,483) 7,256 Equipment inventory ..................... 970 178 12 - 1,160 Other current assets .................... 230 696 124 - 1,050 13 ------------- ------------- ------------- -------------- --------------- Total current assets .................. 16,622 2,866 15,312 (21,483) 13,317 Property and equipment - net................ 116,328 121,767 53,971 - 292,066 Deferred financing fees, net .............. 2,393 950 121 - 3,464 Other assets ............................... 108,708 783 - (109,044) 447 ------------- ------------- ------------ --------------- -------------- Total assets ............................ $ 244,051 $ 126,366 $ 69,404 $ (130,527) 309,294 ============= ============= ============ ================ ============== Liabilities and Stockholder's deficit: Current liabilities: Accounts payable ............................. $ 10,060 $ 17,461 $ 13,992 $ (21,401) $ 20,112 Accrued interest ............................. 6,856 2,522 - - 9,378 Other accrued expenses ....................... 1,521 - - - 1,521 Hedge liability .............................. 1,791 1,465 - - 3,256 Current maturities of long-term debt ......... 63,911 - - - 63,911 ------------- ------------- ------------ --------------- -------------- Total current liabilities .................. 84,139 21,448 13,992 (21,401) 98,178 Long-term debt .................................. 145,362 52,629 29,112 - 227,103 Deferred income taxes ........................... - 16,885 2,857 - 19,742 Future site restoration ........................ - 3,323 674 - 3,997 ------------- ------------- ------------ --------------- -------------- 229,501 94,285 46,635 (21,401) 349,020 Stockholders' equity (deficit)................... 14,550 32,081 22,769 (109,126) (39,726) ------------- ------------- ------------ --------------- -------------- Total liabilities and stockholders' equity (deficit)........................................ $ 244,051 $ 126,366 $ 69,404 $ (130,527) $ 309,294 ============= ============= ============ ================ ==============
(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 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 Stockholder's 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 14 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 March 31, 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 ............... $ 4,461 $ 3,794 $ 2,631 $ - $ 10,886 Gas processing revenues ....................... - 552 118 - 670 Rig revenues .................................. 151 - - - 151 Other ........................................ 4 55 41 - 100 ----------- ----------- ------------ ------------ ------------ 4,616 4,401 2,790 - 11,807 Operating costs and expenses: Lease operating and production taxes .......... 1,878 1,324 707 - 3,909 Depreciation, depletion, and amortization ..... 2,253 3,169 1,392 - 6,814 Rig operations ................................ 121 - - - 121 General and administrative .................... 900 511 287 - 1,698 ----------- ----------- ------------ ------------ ------------ 5,152 5,004 2,386 - 12,542 ----------- ----------- ------------ ------------ ------------ Operating income (loss)........................... (536) (603) 404 - (735) Other (income) expense: Interest income ............................... (33) - - - (33) Amortization of deferred financing fees........ 331 90 6 - 427 Interest expense............................... 6,235 1,682 496 - 8,413 ----------- ----------- ------------ ------------ ------------ 6,533 1,772 502 - 8,807 ----------- ----------- ------------ ------------ ------------ Income (loss) from operations before income tax and extraordinary item......................... (7,069) (2,375) (98) - (9,542) Income tax expense (benefit)...................... - (802) (41) - (843) ----------- ----------- ------------ ------------ ------------ Net income (loss)................................ $ (7,069) $ (1,573) $ (57) $ - $ (8,699) =========== =========== ============ ============ ============
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the three months ended March 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 ----------- ----------- ------------ ------------ ------------ Revenues: Oil and gas production revenues ............... $ 13,031 $ 9,642 $ 5,576 $ - $ 28,249 Gas processing revenues ....................... - 368 68 - 436 Rig revenues .................................. 183 - - - 183 Other ........................................ 3 129 86 - 218 ----------- ----------- ------------ ------------ ------------ 13,217 10,139 5,730 - 29,086 15 Operating costs and expenses: Lease operating and production taxes .......... 2,667 1,699 493 - 4,859 Depreciation, depletion, and amortization ..... 3,204 4,252 1,385 - 8,841 Rig operations ................................ 153 - - - 153 General and administrative .................... 1,315 448 346 - 2,109 General and administrative (Stock-based Compensation)................................ 931 - - - 931 ----------- ----------- ------------ ------------ ------------ 8,270 6,399 2,224 - 16,893 ----------- ----------- ------------ ------------ ------------ Operating income (loss)........................... 4,947 3,740 3,506 - 12,193 Other (income) expense: Interest income ............................... (399) - - 383 (16) Amortization of deferred financing fees........ 347 108 - - 455 Interest expense .............................. 6,172 1,887 105 (383) 7,781 Other ......................................... 16 - - - 16 ----------- ----------- ------------ ------------ ------------ 6,136 1,995 105 - 8,236 ----------- ----------- ------------ ------------ ------------ Income (loss) from operations before income tax and extraordinary item......................... (1,189) 1,745 3,401 - 3,957 Income tax expense (benefit)...................... - 1,179 1,597 - 2,776 Minority interest in income of consolidated 112 foreign subsidiary ............................ - - - (926) (926) ----------- ----------- ------------ ------------ ------------ Net income (loss)................................. $ (1,189) $ 566 $ 1,804 $ (926) $ 255 =========== =========== ============ ============ ============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the three months ended March 31, 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 .................................... $ (7,069) $ (1,573) $ (57) $ $ (8,699) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization ......................... 2,253 3,169 1,392 - 6,814 Deferred income tax benefit............. - (802) (41) - (843) Amortization of deferred financing fees. 331 90 6 - 427 Amortization of debt discount........... - - 113 113 Changes in operating assets and liabilities: Accounts receivable ................ 1,639 (612) 72 - 1,099 Equipment inventory ................ 91 - - - 91 Other ............................. 16 (90) (13) - (87) Accounts payables and accrued expenses ......................... 1,743 2,532 5,092 - 9,367 -------------- ------------ ------------- --------------- -------------- Net cash provided (used) by operating activities ............................... (996) 2,714 6,564 - 8,282 Investing Activities Capital expenditures, including purchases and development of properties ............ (2,119 (2,740) (12,549) - (17,408) -------------- ------------ ------------- --------------- -------------- Net cash used by investing activities ...... (2,119) (2,740) (12,549) - (17,408) 16 Financing Activities Proceeds from long-term borrowings .......... - - 6,096 - 6,096 Payments on long-term borrowings ............ (698) - (21) - (719) -------------- ------------ ------------- --------------- -------------- Net cash provided (used) by financing Activities.................................. (698) - 6,075 - 5,377 -------------- ------------ ------------- --------------- -------------- - Effect of exchange rate changes on cash ..... - (4) (1) - (5) -------------- ------------ ------------- --------------- -------------- Increase (decrease) in cash ................. (3,813) (30) 89 - (3,754) Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605 -------------- ------------ ------------- --------------- -------------- Cash at end of year.......................... $ (220) $ 1,215 $ 2,856 $ - $ 3,851 ============== ============ ============= =============== ==============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the three months ended March 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 -------------- ------------ ------------- --------------- -------------- Operating Activities Net income (loss) ........................... $ (1,189)$ 566 $ 1,804 $ (926) $ 255 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority interest in income of foreign subsidiary ........................... - - - 926 926 Depreciation, depletion, and amortization ......................... 3,204 4,252 1,385 - 8,841 Deferred income tax expense (benefit)... - 1,114 1,581 - 2,695 Amortization of deferred financing fees. 347 108 - - 455 Stock-based compensation ............... 931 - - - 931 Changes in operating assets and liabilities: Accounts receivable ................ 8,475 (1,456) (1,062) 628 6,585 Equipment inventory ................ 44 - - - 44 Other ............................. (141) - 87 - (54) Accounts payables and accrued expenses ......................... (4,668) 2,415 (373) (628) (3,254) -------------- ------------ ------------- --------------- -------------- Net cash provided by operating activities ... 7,003 6,999 3,422 - 17,424 Investing Activities Capital expenditures, including purchases and development of properties ............ (6,872) (6,736) (4,253) - (17,861) Proceeds from sale of oil and gas properties ............................... - 32 12 - 44 -------------- ------------ ------------- --------------- -------------- Net cash provided (used) by investing activities ............................... (6,872) (6,704) (4,241) - (17,817) Financing Activities Proceeds from long-term borrowings .......... 2,500 - 820 - 3,320 Payments on long-term borrowings ............ (2,827) - - - (2,827) Exercise of stock options ................... 10 - - - 10 Deferred financing fees...................... (8) - - - (8) -------------- ------------ ------------- --------------- -------------- Net cash provided (used) by financing activities ............................... (325) - 820 - 495 -------------- ------------ ------------- --------------- -------------- - Effect of exchange rate changes on cash ..... - (37) (1) - (38) -------------- ------------ ------------- --------------- -------------- Increase (decrease) in cash ................. (194) 258 - - 64 Cash at beginning of period ................. 326 1,678 - - 2,004 -------------- ------------ ------------- --------------- -------------- 17 Cash at end of period........................ $ 132 $ 1,936 $ - $ - $ 2,068 ============== ============ ============= =============== =============
Note 6. Business Segments Business segment information about our first quarter operations in different geographic areas is as follows:
Three Months Ended March 31, 2002 ---------------------------------------------------------- U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................ $ 4,616 $ 7,191 $ 11,807 ================== ================== =================== Operating profit ........................ $ 454 $ (199) $ 255 ================== ================== General corporate ....................... (990) Interest expense and amortization of deferred financing fees .............. (8,807) ------------------- Income before income taxes ........... $ (9,542) =================== Identifiable assets at March 31, 2002 ... $ 177,214 $ 127,505 $ 304,719 ================== ================== Corporate assets ........................ 4,575 ------------------- Total assets ......................... $ 309,294 ===================
Three Months Ended March 31, 2001 ---------------------------------------------------------- U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................ $ 13,217 $ 15,869 $ 29,086 ================== ================== =================== Operating profit ........................ $ 7,246 $ 7,283 $ 14,529 ================== ================== General corporate ....................... (2,336) Interest expense and amortization of deferred financing fees .............. (8,220) Other income............................. (16) ------------------- Income before income taxes ........... $ 3,957 ===================
Year Ended December 31, 2001 ---------------------------------------------------------- U.S. Canada Total ------------------ ------------------ ------------------- Identifiable assets...................... $ 124,993 $ 174,063 $ 299,056 ================== ================== Corporate assets......................... 4,657 ------------------- Total assets.......................... $ 303,713 ===================
Note 7. 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. 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 18 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 March 31, 2002.
Time Period Notional Quantities Price Fair Value -------------------------------------- ---------------------------------- ------------------------------ ------------ April 1, 2002 - October 31, 2002 20,000 Mcf/day of natural gas Fixed price swap $2.60-$2.95 $(3.3) 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 liabilities of $38.2 million on that date and a deferred tax asset of $7.2 million. During the first quarter of 2002 the fair value of the hedge increased by $2.6 million. For the three months ended March 31, 2002, the ineffective portion of the cash flow hedges were not material As of March 31, 2002, $2.6 million of deferred net losses on derivative instruments were recorded in other comprehensive income, of which $2.6 million is expected to be reclassified to earnings during the next seven-month period. All hedge transactions are subject to the Company's risk management policy, 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. 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 March 31, 2002, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of $1.4 million and a commodity price decrease of 10% would have resulted in a favorable change in fair market value of $1.4 million. Note 8. 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. 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 interest in the 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 limits 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 March 31, 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 19 Note 9. Comprehensive Income Comprehensive income includes net income, losses and certain items recorded directly to Stockholder's Equity and classified as Other Comprehensive Income. The following table illustrates the calculation of comprehensive income (loss) for the quarter ended March 31, 2002:
Three Months Ending March 31, 2002 (In thousands) --------------------------------- Accumulated other comprehensive loss at December 31, 2001....................... $ (13,561) Net loss..................................................................... $ (8,699) Other Comprehensive loss : Hedging derivatives (net of tax) - See Note 6 Change in fair market value of outstanding hedge positions................. (2,075) Foreign currency translation adjustment...................................... (367) ------------- Other comprehensive loss........................................................ (2,442) (2,442) ------------- Comprehensive loss.............................................................. (11,141) ============= ------------ Accumulated other comprehensive loss at March 31, 2002.......................... $ (16,003) ============
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES PART I Item 2. Management's Discussion and Analysis of Financial Condition and Results of perations ------------------------------------------------------------------------------- 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. General We have incurred net losses in three of the last four years and the quarter ended March 31, 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. During 2001 crude oil and natural gas prices weakened substantially from the 2000 levels. Prices improved during the first quarter of 2002 from their year end 2001 levels. In addition, because our proved reserves will decline as crude oil, natural gas and natural gas liquids are produced, unless we are successful in acquiring 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. If crude oil and natural gas prices return to the depressed levels experienced in the last six months of 2001, or if our production levels decrease, our revenues, cash flow from operations and financial condition will be materially adversely affected. 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. 20 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. The table below illustrates how natural gas prices fluctuated over the course of 2001 and the first quarter of 2002. "Index" represents the last three days average of NYMEX traded contracts index price. The "Realized" price is the natural gas price realized by the Company during the quarter, and it includes the impact of our hedging activities.
(in $ per Mcf) Natural Gas Prices by Quarter Quarter ended ------------------------------------------------------------------------- March 31, June 30, September 30, December 31, March 31, 2001 2001 2001 2001 2002 ------------- ------------ ----------------- --------------- ------------- Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 $ 2.38 Realized 4.85 3.41 2.26 2.09 2.21
The NYMEX natural gas price on May 14, 2002 was $3.85 per Mcf. Prices for crude oil have followed a similar path as the commodity market fell throughout 2001and the quarter of 2002. The table below contains the last three days average of NYMEX traded contracts index price ("Index") and the prices realized by the Company during each quarter for 2001 and the first quarter of 2002..
(in $ per Bbl) Crude oil Prices by Quarter Quarter ended ------------------------------------------------------------------------------ March 31, June 30, September 30, December 31, March 31, 2002 2001 2001 2001 2001 2002 ------------- ------------ ----------------- --------------- ----------------- Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 $ 19.48 Realized 27.22 25.32 25.06 18.72 16.64
The NYMEX crude oil price on May 14, 2002 was $29.36 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 March 31, 2002, Barrett Resources Corporation ("Barrett") had a swap call on either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day at Barrett'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 March 31, 2002, the fair market value of the remaining fixed price hedge agreement was a liability of approximately $3.3 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 March 31, --------------------------------- 2002 2001 ----------- --- ---------- Operating Revenue (in thousands): Crude Oil Sales ........................... $ 1,232 $ 3,602 Natural Gas Sales ........................... 8,782 22,426 Natural Gas Liquids Sales.................... 872 2,221 Processing Revenue........................... 670 436 Rig Operations............................... 151 183 Other........................................ 100 218 ----------- --- ---------- $ 11,807 $ 29,086 =========== === ========== 21 Operating Income (Loss) in thousands)........ $ (735) $ 12,193 Crude Oil Production (MBBLS)................. 74.0 132.3 Natural Gas Production (MMCFS)............... 3,973.1 4,626.8 Natural Gas Liquids Production (MBBLS)....... 68.4 78.1 Average Crude Oil Sales Price ($/BBL)........ $ 16.64 $ 27.22 Average Natural Gas Sales Price ($/MCF)...... $ 2.21 $ 4.85 Average Liquids Sales Price ($/BBL).......... $ 12.76 $ 28.44 Comparison of Three Months Ended March 31, 2002 to Three Months Ended March 31, 2001 Operating Revenue. During the three months ended March 31, 2002, operating revenue from crude oil, natural gas and natural gas liquid sales decreased to $10.9 million compared to $28.2 million in the three months ended March 31, 2001. The decrease in revenue was primarily due to decreased prices realized during the period, and by a decline in production volumes. Lower commodity prices impacted crude oil and natural gas revenue by $14.8 million while reduced production volumes had a $2.5 million negative impact on revenue. Average sales prices net of hedging losses for the quarter ended March 31, 2002 were: o $ 16.64 per Bbl of crude oil, o $ 12.76 per Bbl of natural gas liquid, and o $ 2.21 per Mcf of natural gas Average sales prices net of hedging losses for the quarter ended March 31, 2001 were: o $27.22 per Bbl of crude oil, o $28.44 per Bbl of natural gas liquid, and o $ 4.85 per Mcf of natural gas Crude oil production volumes declined from 132.3 MBbls during the quarter ended March 31, 2001 to 74.0 MBbls for the same period of 2002, primarily as a result of the de-emphasis on crude oil drilling in prior periods, a natural decline in production and the sale of non-core properties in 2001. Natural gas production volumes declined to 3,973.1 MMcf for the three months ended March 31, 2002 from 4,626.8 MMcf for the same period of 2001. This decline was primarily due to the sale of non-core properties in late 2001 and the natural decline in production, 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 March 31, 2002 decreased to $3.9 million from $4.9 million for the same period in 2001. The decrease in LOE is primarily due to a decrease in production tax expense due to higher commodity prices in the quarter ended March 31, 2001 compared to the same period of 2002. Our LOE on a per MCFE basis for the three months ended March 31, 2002 was $0.81 per MCFE compared to $0.82 for the same period of 2001. The decrease in the per MCFE expense was due to a reduced expense offset by a decline in production volumes in the first quarter of 2002 compared to the same period in 2001. General and adminsitrative ("G&A") Expenses. G&A expenses decreased from $2.1 million for the first three months of 2001 to $1.7 million for the first three months of 2002. G&A expense on a per MCFE basis was $0.34 for the first quarter of 2002 compared to $0.36 for the same period of 2001. The decrease in G&A expense was primarily due to a decrease in consulting fees in the first quarter of 2002 as compared to the first quarter of 2001. Additionally we incurred higher medical insurance cost in the first quarter of 2001 compared to the same period of 2002. The decrease in G&A expense on a per MCFE basis was due to lower cost offset by a decline in production volumes during the first quarter of 2002 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 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 22 recognized approximately $931,000 as stock-based compensation expense during the quarter ended March 31, 2001 related to these repricings. 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 $6.8 million for the three months ended March 31, 2002 from $8.8 million for the same period of 2001. Our DD&A on a per MCFE basis for the three months ended March 31, 2002 was $1.42 per MCFE compared to $1.50 in 2001. These decreases were due to a reduction in the full cost pool as the result of a ceiling limitation write-down relating to our Canadian producing properties at December 31, 2001 as well as reduced production volumes in 2002. Interest Expense. Interest expense increased to $8.4 million for the first three months of 2002 compared to $7.8 million in 2001. The increase was due to an increase in long-term debt primarily relating to the Grey Wolf facility. Minority interest. We owned a 49% 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 thee months of 2001 was $926,000. As of March 31, 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 $843,000 for the first three months of 2002 compared to an expense of $2.8 million for the same period of 2001. This decrease is due to reduced profitability in our operations, primarily as a result of lower commodity prices. 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 financing activities, including sales of production payments to Mirant Americas and funding from the Grey Wolf 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 down-turns in commodity prices, such as that experienced in the last six 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. Prices for natural gas and crude oil have increased substantially since March 31, 2002; however, we cannot assure you that these prices can be sustained in the future. 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 produced by us 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 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 The Company deferred an interest payment of $11 million dollars, related to Old Notes and the Second Lien Notes, due on May 1, 2002. The Company has a 30-day grace period in which to make this $11 million payment before an "event of default" occurs. Should such 30-day period expire without the interest payment being made, the event of default would also result in an event of default under the indenture related to the First Lien Notes. Such event of default would allow for the holders of the Old Notes, the First Lien Notes and the Second Lien Notes to declare the entire principal and unpaid interest on all of the Company's outstanding notes($254.5 million) to be due and payable. 23 Working Capital. At March 31, 2002, we had current assets of $13.3 million and current liabilities of $98.2 million resulting in a working capital deficit of $84.9 million. This compares to a working capital deficit of $5.0 million at December 31, 2001 and working capital deficit of $31.1 million at March 31, 2001. The majority of our current liabilities at March 31, 2002, were current maturities of long-term debt of $63.9 million, including $63.5 million of our Fires Lien Notes due March 2003, trade accounts payable of $17.8 million, revenues due third parties of $2.3 million, accrued interest of $9.4 million and hedge liability of $3.3 million. Our capital resources and liquidity are affected by the timing of our interest payments of approximately $4.1 million each March 15, $11.0 million each May 1, $4.1 million each September 15, and $11.0 million each 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. We will need additional funds in the future for both the development of our assets and the service of our debt, including the payment of periodic interest and the repayment of the $63.5 million in principal amount of the First Lien Notes maturing in March 2003 and the $191.0 million of the Second Lien Notes and Old Notes maturing in November 2004. In order to meet the goals of developing our assets and servicing our debt obligations, we will be required to obtain additional sources of capital and/or reduce or reschedule our existing cash requirements. In order to do so, we may pursue one or more of the following alternatives: o refinancing 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; o issuing debt or equity securities or otherwise raising additional funds; or o selling all or a portion of our existing assets, including interests in our assets. 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. In addition, the volatility of crude oil and natural gas prices reduce our cash flow from operations. Capital expenditures. Capital expenditures, excluding property divestitures during the first three months of 2002, were $17.4 million compared to $17.8 million during the same period of 2001. The table below sets forth the components of these capital expenditures on a historical basis for the three months ended March 31, 2002 and 2001.
Three Months Ended March 31 -------------------------------------------- 2002 2001 ---------------------- --------------------- Expenditure category (in thousands): Acquisitions................................... $ 28 $ 22 Development.................................... 17,249 17,726 Facilities and other........................... 131 88 --------------- --------------- Total...................................... $ 17,408 $ 17,836 =============== ===============
Investing activities used $17.4 million net during the first three months of 2002, which was utilized primarily for the development of crude oil and natural gas properties and other facilities. This compares to using $17.8 million net during the first three months of 2001, which was utilized for the development of crude oil and natural gas properties and other facilities. As cash flow permits our current budget for capital expenditures for the last nine months of 2002 other than acquisition expenditures is approximately $20.0 million. The remaining portion of such expenditures is largely discretionary and will be made primarily for the development of existing properties. Additional capital expenditures may be 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 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 will 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: 24 Three Months Ended March 31, ----------------------- 2002 2001 ----------- --------- Net cash provided by operating activities $ 8,282 $ 17,424 Net cash provided by financing activities 5,377 495 Net cash used in investing activities (17,408) (17,817) ----------- --------- Total $ (3,749) $ 102 =========== ========== Operating activities during the three months ended March 31, 2002 provided us $8.3 million cash compared to $17.4 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 $5.4 million for the first three months of 2002 compared to providing $495,000 for the same period of 2001. Current Liquidity Needs. For several years, we have sought to improve our liquidity in order to allow us to meet our debt service requirements and to maintain and increase existing production. Our sale in March 1999 of our First Lien Notes allowed us to refinance our bank debt, meet our near-term debt service requirements and make limited crude oil and natural gas capital expenditures. In October 1999, we sold a dollar denominated production payment for $4.0 million relating to existing natural gas wells in South Texas to a unit of Southern Energy, Inc. which is now known as Mirant Americas Energy Capital, L.P. and in 2000 and 2001, we sold additional production payments for $6.4 million and $11.7 million, respectively, relating to additional natural gas wells in the Edwards Trend to Mirant Americas. We have the ability to sell up to $50 million to Mirant for drilling opportunities in South Texas. In December 1999, Abraxas and Canadian Abraxas, completed an Exchange Offer whereby we exchanged our new 11.5% Senior Secured Notes due 2004 (the "Second Lien Notes"), common stock and contingent value rights for approximately 98.43% of our outstanding 11.5% Senior Notes due 2004, Series D (the "Old Notes"). The Exchange Offer reduced our long-term debt by approximately $76 million after expenses. In March 2000, we sold our interest in certain crude oil and natural gas properties that we owned and operated in Wyoming. Simultaneously, a limited partnership of which one of our subsidiaries was the general partner, accounted for on the equity method of accounting sold its interest in crude oil and natural gas properties in the same area. Our net proceeds from these transactions were approximately $34.0 million. During 2001, we sold assets in the United States and Canada. Our net proceeds from these transactions were approximately $29 million. These proceeds were used to invest in additional producing properties. In December 2001, Grey Wolf entered into a financing agreement with Mirant Canada for CDN $150 million (approximately US $96 million), which is non-recourse to Abraxas. Initial borrowings from this facility of approximately US $25 million were used to retire Grey Wolf's existing bank facility and for general corporate purposes. Up to US $71 million is available to finance drilling of wells and related activities under this credit facility. In March 2002, our wholly owned Canadian subsidiaries, Grey Wolf and Canadian Abraxas, entered into a definitive Purchase and Sale Agreement related to the sale of their interest in a natural gas plant and the associated reserves. The sale, effective March 1, 2002, is scheduled to close in the second quarter of 2002 with estimated net proceeds of US $21.5 million. We have also recently engaged Randall & Dewey, Inc. to explore a potential sale of certain properties located in Texas. The data room was opened in March of 2002, with bids due in the second quarter of 2002. There are no definitive agreements related to any potential sale and we cannot assure you that any sale will occur or, if it does, the sale price that we would receive. The Company deferred an interest payment of $11 million dollars, related to Old Notes and the Second Lien Notes, due on May 1, 2002. The Company has a 30-day grace period in which to make this $11 million payment before an "event of default" occurs Should such 30-day period expire without the interest payment being made, the event of default would also result in an event of default under the indenture related to the First Lien Notes. Such event of default would allow for the holders of the Old Notes, the First Lien Notes and the Second Lien Notes to declare the entire principal and unpaid interest on all of the Company's outstanding notes ($254.5 million) to be due and payable. Future Capital Resources. We will have four principal sources of liquidity going forward: (i) cash on hand, (ii) cash flow from operations, (iii) the 25 production payment with Mirant Americas and (iv) 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. The First Lien Notes indenture and the Second Lien Notes indenture 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. 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. Due to our current debt levels and the restrictions contained in the indentures described above, our best opportunity for additional sources of 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. 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 other such 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 March 31, 2002.
Payments due in: ---------------------------------------------------------------------------- Contractual Obligations ---------------------------------------------------------------------------- 2005 and Total 2002 2003 2004 after ---------------------------------- ---------------------------------------------------------------------------- Dollars in thousands ---------------------------------- --------------- -------------- -------------- --------------- -------------- Long-Term Debt (1) (2) $283,591 $ - $63,500 $190,979 $ 29,112 (3) Operating Leases (4) 1,381 396 336 236 413
(1) Includes $63.5 million of the First Lien Notes, $191.0 million of the Old Notes and Second Lien Notes, $29.1 million under the Grey Wolf Facility and $7.4 million under the production payment with Mirant Americas. (2) Mirant Americas is paid a percentage of revenue from South Texas wells on which they have advanced production payments, the amount of the future payments is dependent on production from the subject wells. As a result, no payments are reflected in the table. (3) The Grey Wolf 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 March 31, 2002 ($29.1 million) although we will be making payments prior to 2007. For more information on the Grey Wolf Facility, you should read the description under "Grey Wolf Facility." 26 (4) 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 $20 million. Long-Term Indebtedness. Old Notes. On November 14, 1996, the Company consummated the offering of $215.0 million of it's 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. 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 the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on November 1 of the years set forth below: Year Percentage ---- ---------- 2001............................................ 102.875% 2002 and thereafter............................. 100.000% 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"), a wholly owned subsidiary of the Company. The guarantee is a general unsecured obligation of Sandia and ranks pari passu in right of payment to all unsubordinated indebtedness of Sandia and senior in right of payment to all subordinated indebtedness of Sandia. The guarantee is 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 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 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. 27 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 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. 28 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 the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on December 1 of the years set forth below: Year Percentage ----- ---------- 2001................................................... 102.875% 2002 and thereafter.................................... 100.000% 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; (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 29 (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 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 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 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 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 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. The Grey Wolf Facility matures in 2007. 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 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 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. Events of Default. The Grey Wolf Facility contains customary events of default, including nonpayment of principal or interest, violations of covenants, 30 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 crude oil and natural gas sales from all of its properties. Hedging Activities. 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 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 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 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 position as of March 31, 2002.
Time Period Notional Quantities Price Fair Value ---------------------------------------- ------------------------------ ------------------------------ ---------------- April 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $2.60-$2.95 $(3.3) 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, the Company 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. The Company 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 quarter of 2002 the fair value of outstanding liabilities decreased by $2.6 million. For the three months ended March 31, 2002, the ineffective portion of the cash flow hedges were not material. As of March 31, 2002, $2.6 million of deferred net losses on derivative instruments were recorded in Other Comprehensive Income/Loss, which is expected to be reclassified to earnings during the next seven-month period. All hedge transactions are subject to the Company's risk management policy, 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. 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 March 31, 2002, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of $1.4 million and a commodity price decrease of 10% would have resulted in a favorable change in fair market value of $1.4 million. 31 Net Operating Loss Carryforwards. At December 31, 2001 the Company 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, the Company 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, the Company 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 the Company's 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, the Company has established a valuation allowance of $39,670,000 for deferred tax assets at December 31, 2001 and March 31,2002. 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 three months ended March 31, 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 $1.1 million for the three months ended March 31, 2002. Hedging Sensitivity The fair value of our hedge instrument was determined based on NYMEX forward price quotes as of March 31, 2002. As of March 31, 2002, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of our hedging instrument of $1.4 million and a commodity price decrease of 10% would have resulted in a favorable change in the fair value of our hedge instrument of $1.4 million. The following table sets forth our hedge position as of March 31, 2002.
Time Period Notional Quantities Price Fair Value --------------------------------------------- ---------------------------- ------------------------- --------------- April 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $(3.3) million gas or 1,000 Bbl/day of $2.60-$2.95 natural gas crude oil or $18.90 Crude oil
Interest rate risk At March 31, 2002, substantially all of our long-term debt is at fixed interest rates and not subject to fluctuations in market rates. 32 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 $2.5 million for the three months ended March 31, 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 $125,000. 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. 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 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. 33 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 (b) Reports on Form 8-K: 1. Current Report on the Form 8-K filed on January 3, 2002. Other Events, including a press release relating to the announcement of the Company's Canadian project financing. 2. Current Report on the Form 8-K filed on March 27, 2002. Other Events, including a press release relating to the announcement of the Company's 2001 year end and fourth quarter financial results. 3. Current Report on the Form 8-K filed on March 28, 2002. Other Events, including a press release relating to a definitive purchase and sale agreement by wholly owned Canadian subsidiaries for the sale of their interest in a natural gas processing plant and related reserves. 4. Current Report of the Form 8-K filed on April 23, 2002. Other Events, including a press release relating to Canadian winter drilling activity. 5. Current Report on the Form 8-K filed on May 1, 2002. Other Events, including a press release relating to deferral of interest payment. 6. Current Report on the Form 8-K filed on May 14, 2002. Other Events, including a press release relating to the announcement of the Company's first quarter 2002 financial results and West Texas drilling results. 34 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: May 17, 2002 By:/s/ -------------- ------------------------------- ROBERT L.G. WATSON, President and Chief Executive Officer Date: May 17, 2002 By:/s/ -------------- ------------------------------- CHRIS WILLIFORD, Executive Vice President and Principal Accounting Officer 35