-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TkW3dFr5ppmeTCTlMVfC1TZdtvT3HYWJNbEE8euv44LAC3VMIrVHIAutOdBaQOG0 HENKgkamp8S9WMTfJX4m/g== 0000867665-99-000024.txt : 19991215 0000867665-99-000024.hdr.sgml : 19991215 ACCESSION NUMBER: 0000867665-99-000024 CONFORMED SUBMISSION TYPE: 10-Q/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991214 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP CENTRAL INDEX KEY: 0000867665 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 742584033 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q/A SEC ACT: SEC FILE NUMBER: 000-19118 FILM NUMBER: 99774376 BUSINESS ADDRESS: STREET 1: 500 N LOOP 1604 EAST STE 100 CITY: SAN ANTONIO STATE: TX ZIP: 78232 BUSINESS PHONE: 2104904788 MAIL ADDRESS: STREET 1: 500 N LOOP 1604 EAST STE 100 CITY: SAN ANTONIO STATE: TX ZIP: 78232 10-Q/A 1 10-Q/A UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) FORM 10-Q/A Number 1 (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended September 30, 1999 ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-19118 ABRAXAS PETROLEUM CORPORATION ---------------------------------------------------------------------- (Exact name of Registrant as specified in its charter) Nevada 74-2584033 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization Identification Number) 500 N. Loop 1604, East, Suite 100, San Antonio, Texas 78232 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code (210) 490-4788 Not Applicable (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period that the restraint was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X or No __ The number of shares of the issuer's common stock outstanding as of November 10, 1999, was: Class Shares Outstanding Common Stock, $.01 Par Value 6,352,672 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES FORM 10 - Q/A Number 1 Management's Discussion and Analysis of Financial Condition and Results of Operations is amended by inserting disclosure regarding Year 2000 matters.The revised Management's Discussion and Analysis of Financial Condition and Results of Operations is attached hereto. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following is a discussion of the Company's financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with the consolidated financial statements of the Company and the notes thereto, included in the Company's Annual report on Form 10-K filed for the year ended December 31, 1998, which is incorporated herein by reference. Results of Operations The factors which most significantly affect the Company's results of operations are (1) the sales prices of crude oil and natural gas, (2) the level of total sales volumes of crude oil and natural gas, (3) the level of and interest rates on borrowings and (4) the level and success of exploration and development activity. Selected operating data. The following table sets forth certain operating data of the Company for the periods presented.
Three Months Ended Nine Months Ended September 30, September 30, --------------------------- ------------------------------- 1999 1998 1999 1998 ------------ ----------- -------------- ------------- Operating Revenue (in thousands): Crude Oil Sales $ 3,242 $ 2,374 $ 8,506 $ 7,768 Natural Gas Sales 11,074 9,082 32,012 28,699 Natural Gas Liquids Sales 1,526 1,342 3,366 4,939 Processing Revenue 818 668 2,733 2,370 Rig Operations 129 112 328 350 Other 169 421 2,759 1,883 ============ =========== ============== ============= $ 16,958 $ 13,799 $ 49,704 $ 46,009 ============ =========== ============== ============= Operating Income (in thousands) $ 2,982 $ (765) $ 5,278 $ 2,235 Crude Oil Production (MBBLS) 192 178 609 565 Natural Gas Production (MMCFS) 6,273 6,395 20,155 18,874 Natural Gas Liquids Production (MBBLS) 98 238 282 715 Average Crude Oil Sales Price ($/BBL) $ 16.88 $ 13.32 $ 13.98 $ 13.75 Average Natural Gas Sales Price ($/MCF) $ 1.77 $ 1.42 $ 1.59 $ 1.52 Average Liquids Sales Price ($/BBL) $ 15.62 $ 5.64 $ 11.96 $ 6.90
Comparison of Three Months Ended September 30, 1999 to Three Months Ended September 30, 1998 Operating Revenue. During the three months ended September 30, 1999, operating revenue from crude oil, natural gas and natural gas liquid sales increased to $15.8 million from $12.8 million for the same period in 1998. The increase in revenue from crude oil, natural gas and natural gas liquids was primarily due to increased prices received in 1999 as compared to 1998. Increased prices contributed $4.8 million to revenue which was offset by $1.8 million as a result of lower production volumes. The average sales price for crude oil was $16.88 per barrel for the three months ended September 30, 1999 compared to $13.32 for the same period of 1998, natural gas sales prices averaged $1.77 per Mcf for the three months ended September 30, 1999 compared to $1.42 per Mcf for the same period of 1998 and the average sales prices for natural gas liquids were $15.62 per Bbl for the three months ended September 30, 1999 compared to $5.64 for the same period of 1998. Revenue from crude oil production increased from $2.4 million in the third quarter of 1998 to $3.2 million for the same period of 1999. Increased prices contributed $0.6 million while increased production added an additional $0.2 million. The increase in production was primarily due to the acquisition New Cache in January 1999. The New Cache properties contributed $1.3 million and 72 MBbls which offset the loss of production from the Company's properties in the 2 Wamsutter area of Wyoming (the "Wyoming Properties") which were sold in the fourth quarter of 1998. The Wyoming Properties contributed $0.3 million and 25.6 MBbls in the third quarter of 1998. Revenue from natural gas production increased by $2.0 million during the third quarter of 1999 to $11.1 million. The increase in natural gas revenue was primarily attributable to increased prices during the quarter. The average price received during the third quarter of 1999 was $1.77 compared to $1.42 for the same period of 1998. Increased prices contributed $2.2 million offset by $0.2 million due to slightly lower production. The decline in natural gas production volumes were the result of the sale of the Wyoming Properties in the fourth quarter of 1998 Natural gas production in the third quarter of 1998 included 1.6 Bcf from the Wyoming Properties which was offset by 1.7 Bcf in natural gas production from the New Cache acquisition in January 1999. Natural gas liquids revenue increased to $1.5 million for the quarter ended September 30, 1999 compared to $1.3 million for the same period of 1998. Increased prices received for natural gas liquids during the third quarter of 1999 contributed $2.4 million to revenue. Production volume declines had a $2.2 million negative impact on revenue during the three months ended September 30, 1999. Production decreased by 140.4 MBbls to 97.7 MBbls for the three months ended September 30, 1999 from 238.1 MBbls for the same period of 1998. The decline in natural gas liquids volumes was due primarily to the sale of the Wyoming Properties in the fourth quarter of 1998. The Wyoming Properties contributed 132.8 MBbls of natural gas liquids during the third quarter of 1998. Further declines in natural gas liquids production were the result of the closing of the Company's Portilla processing plant in January 1999. The Portilla processing plant contributed 12.6 MBbls of natural gas liquid during the third quarter of 1998. The decline in natural gas liquids production was partially offset by production New Cache which contributed 9.7 MBbls of natural gas liquids during the third quarter of 1999. Lease Operating Expenses. Lease operating expenses and natural gas processing costs ("LOE") for the three months ended September 30, 1999 increased to $4.6 million compared to $4.3 million for the same period in 1998. The increase in LOE was primarily due to the greater number of wells owned by the Company during the period ended September 30, 1999 compared to the same period of 1998. The Company's LOE on a per MCFE basis for the three months ended September 30, 1999 was $0.57 compared to $0.49 for the same period of 1998. The increase on a per MCFE basis was due to a general increase in the cost of services from 1998 to 1999 and from the sale of the Wyoming Properties which were a low cost operating area with LOE per MCFE of $0.19 in 1998. G&A Expenses. General and administrative ("G&A") expenses increased from $1.3 million for the three months ended September 30, 1998 to $1.4 million for the same period of 1999. The increase was due to the hiring of additional staff to manage and develop the Company's properties including the addition of several staff members associated with the New Cache acquisition. G&A expense on a per MCFE basis increased from $0.14 for the quarter ended September 30, 1998 to $0.18 for the same period of 1999. Depreciation, Depletion and Amortization Expenses. Depreciation, depletion and amortization ("DD&A") expense decreased from $8.8 million for the three months ended September 30, 1998, to $7.8 million in the same period of 1999. The Company's DD&A on a per MCFE basis for the three months ended September 30, 1999 was $0.98 per MCFE compared to $0.99 in 1998. The decrease in total DD&A was due to write downs in the full cost pool at December 31, 1998 as a result of depressed commodity prices at that time forcing some of the Company's oil properties to their economic limits much sooner. Interest Expense. Interest expense increased to $10.0 million for the three months ended September 30, 1999 from $7.5 million for the same period of 1998. This increase was attributable to increased borrowings by the Company during the first quarter of 1999. Long-term debt increased from $299.7 million at December 31, 1998, to $346.2 million at September 30, 1999, as a result of the Company's issuing $63.5 million of the Secured Notes in March 1999. Comparison of Nine Months Ended September 30, 1999 to Nine Months Ended September 30, 1998 Operating Revenue. During the nine months ended September 30, 1999, operating revenue from crude oil, natural gas and natural gas liquid sales increased from $41.4 million in the nine months ended September 30, 1998 to $43.9 million for the same period in 1999. Increased production of crude oil and natural gas contributed $2.6 million in additional revenue, while higher crude oil and natural gas prices added revenue of $1.4 million. Lower production of natural gas liquids had a negative impact of $5.2 million offset by $3.6 million from higher prices. Crude oil production increased from 564.9 MBbls for the first nine months of 1998 to 608.6 MBbls for the same period of 1999. Production from the New Cache properties (acquired in January 1999) contributed 228.1 MBbls in 1999 which was offset by declines in the production from the Company's existing properties and 3 from the divestiture of the Wyoming Properties. The Wyoming Properties contributed 74.6 MBbls of crude oil in the nine months ended September 30, 1998. The decline in the production from existing properties was as a result of the de-emphasis of the Company's crude oil exploration and development program in 1999 due to depressed crude oil prices during the first part of 1999. Crude oil prices improved in the third quarter. The average price received for crude oil for the first nine months of 1999 was $13.98 per Bbl compared to $13.75 per Bbl for the same period of 1998. Natural gas production increased by 1,281 MMcf for the first nine months of 1999 to 20,155 MMcf from 18,874 MMcf for the same period of 1998. The acquisition of New Cache contributed 5,200 MMcf during the nine months ended September 30, 1999 which offset the loss of production from the Wyoming Properties, which were sold in the fourth quarter of 1998. For the nine months ended September 30, 1998 the Wyoming Properties contributed 4,599 MMcf. The increase in natural gas volumes contributed $2.0 in additional revenue. Increased natural gas prices received during the nine months ended September 30, 1999 contributed an additional $1.3 to revenue for the period. The average natural gas price received during the first none months of 1999 was $1.59 per Mcf compared to $1.52 per Mcf for the same period of 1998. Revenue from natural gas liquids declined $1.6 million from $4.9 million for the nine months ended September 30, 1998 to $3.4 million for the same period of 1999. Reduced production of natural gas liquids had a negative impact of $5.2 million on revenue for the nine months ended September 30, 1999 which was offset by $3.6 million of increased revenue due to higher prices for the period. Average natural gas liquids sales prices for the six months ended September 30, 1999 were $11.96 per Bbl compared to $6.90 for the same period of 1998. Natural gas liquid production declined to 281.5 MBbls for the nine months ended September 30, 1999 from 715.4 MBbls for the same period of 1998. The decline in natural gas liquids volumes was due to the divestiture of the Wyoming Properties in the fourth quarter of 1998 and the Company's decision to shut down the East White Point and Portilla plants in South Texas. The Wyoming Properties contributed 385.5 MBbls of natural gas liquids during the first nine months of 1998 which was partially offset by 57.2 MBbls from the New Cache properties acquired in January 1999. The Company shut down its East White Point processing plant during the fourth quarter of 1998 and shut down its Portilla Plant in January 1999. The East White Point plant produced 40.4 MBbls of natural gas liquids during the first nine months of 1998 and the Portilla Plant contributed 38.0 MBbls of natural gas liquids during the first nine months of 1998 compared to 2.1 MBbls in 1999. The Company began processing the East White Point gas through a third party plant in April 1999.Total East White Point production through this facility was 37.7 MBbls during the period ended September 30, 1999. The Company also elected not to process its West Texas gas during the first quarter of 1999 due to the depressed prices of natural gas liquids. Processing of the West Texas gas resumed in April 1999 contributing 41.7 MBbls during the period ended September 30, 1999. Lease Operating Expenses. LOE and natural gas processing expenses were $14.0 million for the nine months ended September 30, 1999 compared to $13.4 million for the same period in 1998. The increase of $0.6 million was due to an increase in the number of wells the Company owned as of September 30, 1998 compared to the same period of the prior year. LOE on a per MCFE basis increased to $0.55 per MCFE for the nine months ended September 30, 1999 from $0.50 for the same period of 1998. The increase per MCFE was due to a general increase in the cost of services from 1998 to 1999 as well as from the divestiture of the Wyoming Properties which was a low cost operating area with LOE of $0.16 per MCFE. G&A Expenses. G&A expenses increased from $4.0 million for the nine months ended September 30, 1998 to $4.2 million for the same period of 1999. The increase was primarily due to the hiring of additional staff to manage and develop the Company's properties including the addition of several staff members associated with the New Cache acquisition. G&A expense on a per MCFE basis increased to $0.16 per MCFE from $0.15 for the same period of 1998. Depreciation, Depletion and Amortization Expenses. DD&A expense decreased to $25.8 million for the nine months ended September 30, 1999, from $26.0 million for the same period of 1998. DD&A expense on a per MCFE basis was $1.01 per MCFE for the nine months ended September 30, 1999 compared to $0.98 per MCFE for the nine months ended June 30, 1998. The increase on a per MCFE basis was due to higher finding cost during 1999, including the acquisition of New Cache, in the Company's Canadian operations and the loss of reserves resulting from low commodity prices that forced some of the Company's oil properties to their economic limits much sooner. The increases were partially offset by lower DD&A per MCFE from the U.S. operations as a result of the ceiling test write down of the U.S. full cost pool as of December 31, 1998. Interest Expense. Interest increased to $28.4 million for the nine months ended September 30, 1999 from $22.8 million for the nine months ended September 30, 1998. The increase was due to increased levels of borrowings by the Company during the first nine months of 1999. Long-term debt increased from $299.7 million at December 31, 1998 to $346.2 million at September 30, 1999, as a result of the Company's issuing $63.5 million of its 12.875% Senior Secured Notes due 2003 in late March 1999. General . The Company's 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 produced by the Company. The prices of natural gas, crude oil and natural gas liquids received by the Company improved during the first nine months of 1999. The average natural gas price realized by the Company increased to $1.59 per Mcf during the first nine months of 1999 compared with $1.52 per MCF during the same period of 1998. Crude oil prices increased from $13.75 per Bbl during the nine months of September 1998, to $13.98 per Bbl for the same period of 1999. Natural gas liquids prices increased to $11.96 per Bbl compared to $6.90 per Bbl in 1998. The prices of crude oil and natural gas have strengthened in the third 4 quarter and continued to strengthen in the fourth quarter. In addition, the Company's proved reserves will decline as crude oil, natural gas and natural gas liquids are produced unless the Company is successful in acquiring properties containing proved reserves or conducts successful exploration and development activities. In the event crude oil, natural gas and natural gas liquid prices return to depressed levels or if the Company's production levels decrease, the Company's revenues, cash flow from operations and profitability will be materially adversely affected. Delisting of Common Stock on The Nasdaq National Market The Company's common stock has been delisted from The Nasdaq National Market ("NMS") due to the Company's inability to meet the minimum net tangible assets and "inside bid" price requirements for NMS listed companies. The Company's stock is quoted and traded on the OTC Bulletin Board under the symbol, AXAS. Liquidity and Capital Resources General: Capital expenditures excluding property divestitures during the nine months ended September 30, 1999 were $115.3 million compared to $41.7 million during the same period of 1998. The table below sets forth the components of these capital expenditures on a historical basis for the six months ended September 30, 1999 and 1998. Nine Months Ended September 30 -------------------------------------- 1999 1998 ------------------- ------------------ Expenditure category (in thousands): Acquisitions $ 92,586 $ 2,400 Development 21,006 35,475 Facilities and other 1,658 3,786 --------------- ------------ Total $ 115,250 $ 41,661 =============== ============ At September 30, 1999, the Company had current assets of $32.5 million and current liabilities of $34.3 million resulting in a working capital deficit of $1.8 million. This compares to working capital of $50.7 million at December 31, 1998 and a working capital deficit of $9.1 million at September 30, 1998. The material components of the Company's current liabilities at September 30, 1999 include trade accounts payable of $8.5 million, revenues due third parties of $10.5 million and accrued interest of $13.6 million. Operating activities during the nine months ended September 30, 1999 provided $9.3 million in cash to the Company compared to $6.1 million in the same period in 1998. Net income plus non-cash expense items during 1999 and net changes in operating assets and liabilities accounted for most of these funds. Investing activities required $100.4 million net during the first nine months of 1999, $92.6 million of which was utilized for the acquisition of oil and gas properties, $21.0 million of which was utilized for the development of crude oil and natural gas properties and other facilities, and $1.7 million of which was utilized for facilities and other. Divestitures of oil and gas properties provided $14.8 million. This compares to $41.7 million required during the same period of 1998, $35.5 million of which was utilized for the development of crude oil and natural gas properties and other facilities, and $2.4 million for the acquisition of oil and gas properties. Financing activities provided $43.9 million for the first nine months of 1999 compared to providing $39.5 million for the same period of 1998. Financing activities include the proceeds of $63.5 million from the issuance of the Secured Notes in March 1999 and borrowings under the Credit Facility of $19.5 million, which were offset by the repayment of the Credit Facility in the amount of $35.2 million in March 1999. The Company's current budget for capital expenditures for the last three months of 1999 other than acquisition expenditures is approximately $6.0 million. Such expenditures will be made primarily for the development of existing properties. Additional capital expenditures may be made for acquisitions of producing properties if such opportunities arise, but the Company currently has no agreements, arrangements or undertakings regarding any material acquisitions. The Company has no material long-term capital commitments and is consequently able to adjust the level of its 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 commodity prices remain at depressed levels or decline further, reductions in the capital expenditure budget may be required. Current Liquidity Needs. The Company has historically funded its operations and acquisitions primarily through its cash flow from operations and borrowings under the Credit Facility and other credit sources. In March 1999, the Company 5 issued $63.5 million principal amount of the Secured Notes and repaid all amounts outstanding under the Credit Facility and approximately $10.0 million of debt assumed in connection with the acquisition of New Cache. Due to severely depressed prices for crude oil and natural gas during the early part of 1999, the Company's cash flow from operations has been substantially reduced. In October 1999 the Company sold a dollar denominated production payment for $ 4.0 million relating to existing natural gas wells in the Edwards Trend in South Texas to a unit of Southern Energy, Inc. The Company has the ability to sell up to $50 million to Southern for drilling opportunities in the Edwards Trend. In November 1999 the Company announced that an oral agreement had been reached with an informal committee of the holders of the Series D Notes, representing a majority of the outstanding principal amount of the Series D Notes. The Company has been exploring alternatives to increase its liquidity, including the restructuring of the Company's indebtedness. The Company has been involved in discussions with the members of the informal committee, and as a result of these discussions, the Company and the informal committee have agreed to the following restructuring proposal: o Noteholders will exchange the Series D Notes for new notes with a face amount equal to 70% of the principal amount of the existing Series D Notes with the same interest rate; o The new notes will have a second priority lien on substantially all of the assets of Abraxas; o Noteholders will receive equity equal to 72% of the equity of the restructured company; o Noteholders will receive a contingent value right that will allow them to receive additional equity if the price of Abraxas common stock does not reach certain levels over the 18 month period following the consummation of the restructuring; and o Noteholders will appoint four members of a new seven-member board of directors The closing of the restructuring is subject to the satisfaction of certain customary conditions to closing including board approval and the exchange of at least 95% of the principal amount of the Series D Notes in exchange for new notes with terms described above. The Company currently expects that the proposed restructuring will be completed on or about December 15, 1999. The Company will have four principal sources of liquidity going forward: (i) cash on hand, (ii) cash flow from operations (iii) the Production Payment and (iv) proceeds from the sale of non-core assets. While the availability of capital resources 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 the Production Payment and the proceeds from the sale of certain non-core properties will be adequate to fund operations and planned capital expenditures. The Company's ability to obtain additional financing will be substantially limited under the terms of the Series D Notes , the new notes to be issued in the restructuring and the Secured Notes. Substantially all of the Company's crude oil and natural gas properties and natural gas processing facilities are subject to a first lien or charge for the benefit of the holders of the Secured Notes and , if the restructuring is consummated, a second lien or charge for the benefit of the holders of the new notes. Thus, the Company will be required to rely on its cash flow from operations to fund its operations and service its debt. The Company may also choose to issue equity securities or sell additional assets to fund its operations, although the Indentures governing the Company's outstanding Secured Notes and Series D Notes substantially limit the Company's use of the proceeds of any such asset sales. Due to the Company's diminished cash flow from operations and the resulting depressed prices for its common stock, there can be no assurance that the Company would be able to obtain equity financing on terms satisfactory to the Company. Long-Term Indebtedness Series D Notes. On November 14, 1996, Abraxas and Canadian Abraxas consummated the offering of $215.0 million of their 11.5% Senior Notes due 2004, Series A, which were exchanged for the Series B Notes in February 1997. On January 27, 1998, Abraxas and Canadian Abraxas completed the sale of $60.0 million of the Series C Notes. The Series B Notes and the Series C Notes were subsequently exchanged for $275.0 million in principal amount of the Series D Notes in June 1998. Interest on the Series D 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 Series D Notes are redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas, on or after November 1, 2000, 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: 6 Year Percentage 2000...................................... 105.750% 2001...................................... 102.875% 2002 and thereafter....................... 100.000% In addition, at any time on or prior to November 1, 1999, Abraxas and Canadian Abraxas may, at their option, redeem up to 35% of the aggregate principal amount of the Series D Notes originally issued with the net cash proceeds of one or more equity offerings, at a redemption price equal to 111.5% of the aggregate principal amount of the Series D Notes to be redeemed, plus accrued and unpaid interest to the date of redemption; provided, however, that after giving effect to any such redemption, at least 65% of the aggregate principal amount of the Series D Notes remains outstanding. The Series D 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 Series D Notes rank senior in right of payment to all future subordinated indebtedness of Abraxas and Canadian Abraxas. The Series D Notes are, however, effectively subordinated to the Secured Notes to the extent of the value of the collateral securing the Secured Notes (the "Collateral"). The Series D Notes are unconditionally guaranteed, on a senior basis, jointly and severally, by the New Cache and Sandia. The guarantees are general unsecured obligations of New Cache and Sandia and rank pari passu in right of payment to all unsubordinated indebtedness of New Cache and Sandia and senior in right of payment to all subordinated indebtedness of New Cache and Sandia. These guarantees are effectively subordinated to the Secured Notes to the extent of the value of the Collateral. Upon a Change of Control (as defined in the Series D Indenture), each holder of the Series D Notes will have the right to require Abraxas and Canadian Abraxas to repurchase all or a portion of such holder's Series D 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 Series D 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. The Series D Indenture provides, among other things, that the Company may not, and may not cause or permit certain of its subsidiaries, including Canadian Abraxas, 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, guarantee any indebtedness of Abraxas or transfer any of its assets to Abraxas except for such encumbrances or restrictions existing under or by reason of: (i) applicable law; (ii) the Series D Indenture; (iii) the Credit Facility (as defined in the Series D Indenture); (iv) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries; (v) any instrument governing indebtedness assumed by the Company in an acquisition, which encumbrance or restriction is not applicable to such subsidiaries or the properties or assets of such subsidiaries other than the entity or the properties or assets of the entity so acquired; (vi) customary restrictions with respect to subsidiaries of the Company pursuant to an agreement that has been entered into for the sale or disposition of capital stock or assets of such subsidiaries to be consummated in accordance with the terms of the Series D Indenture solely in respect of the assets or capital stock to be sold or disposed of; (vii) any instrument governing certain liens permitted by the Indenture, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such lien; or (viii) an agreement governing indebtedness incurred to refinance the indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (ii), (iii) or (v) 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 Series D Notes in any material respect as determined by the Board of Directors of the Company 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 (ii), (iii) or (v). Secured Notes: In March 1999 the Company consummated the sale of $63.5 million of the Secured Notes due 2003. Interest on the Secured Notes is payable semi-annually in arrears on March 15 and September 15, commencing September 15, 1999. The Secured Notes are redeemable, in whole or in part, at the option of Abraxas on or after March 15, 2001, 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 March 15 of the years set forth below: Year Percentage 2001................................... 103.000% 2002 and thereafter.................... 100.000% 7 At any time, or from time to time, prior to March 15, 2001, Abraxas may, at its option, use all or a portion of the net cash proceeds of one or more equity offerings to redeem up to 35% of the aggregate original principal amount of the Notes at a redemption price equal to 112.875% of the aggregate principal amount of the Notes to be redeemed, plus accrued and unpaid interest. The Secured 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 Secured Notes are unconditionally guaranteed (the "Guarantees") on a senior basis, jointly and severally, by Canadian Abraxas, New Cache and Sandia (collectively, the "Guarantors"). 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 Canadian Abraxas. Upon a Change of Control, each holder of the Secured Notes will have the right to require Abraxas to repurchase such holder's Secured 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 Issuers will be obligated to offer to repurchase the Secured 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 Secured Notes Indenture contains certain covenants that limit the ability of Abraxas and certain of its subsidiaries, including the Guarantors (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 the Company. The Secured Notes Indenture provides, among other things, that the Company 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: (i) applicable law; (ii) the Indentures; (iii) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries; (iv) any instrument governing indebtedness assumed by the Company 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; (v) agreements existing on the Issue Date (as defined in the Secured Notes Indenture) to the extent and in the manner such agreements were in effect on the Issue Date; (vi) customary restrictions with respect to subsidiaries of the Company 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 Secured Notes Indenture or any Security Documents (as defined in the Secured Notes Indenture) solely in respect of the assets or capital stock to be sold or disposed of; (vii) any instrument governing certain liens permitted by the Secured 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 (viii) an agreement governing indebtedness incurred to refinance the indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (ii), (iv) or (v) 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 Secured Notes in any material respect as determined by the Board of Directors of the Company 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 (ii), (iv) or (v) 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 Secured Notes, (B) the refinancing results in an improvement on a pro forma basis in the Company's Consolidated EBITDA Coverage Ratio (as defined in the Secured 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. Hedging Activities. The Company's results of operations are significantly affected by fluctuations in commodity prices and seeks to reduce its exposure to price volatility by hedging its production through swaps, options and other commodity derivative instruments. In November 1996, the Company assumed hedge agreements extending through October 2001 with a counterparty involving various quantities and fixed prices. These hedge agreements provided for the Company to make payments to the counterparty to the extent the market prices, determined based on the price for crude oil on the NYMEX and the Inside FERC, Tennessee Gas Pipeline Co. Texas (Zone O) price for natural gas exceeded certain fixed prices and for the 8 counterparty to make payments to the Company to the extent the market prices were less than such fixed prices. The Company accounted for the related gains or losses (a gain of $204,600 during the first quarter of 1999) in crude oil and natural gas revenue in the period of the hedged production. The Company terminated these hedge agreements in January 1999 and was paid $750,000 by the counterparty for such termination. This amount is included in other income in the accompanying financial statements. In March 1998, the Company entered into a costless collar hedge agreement with Enron Capital and Trade Resources Corp. for 2,000 Bbls of crude oil per day with a floor price of $14.00 per Bbl and a ceiling price of $22.30 per Bbl for crude oil on the NYMEX. The agreement was effective April 1, 1998 and extended through March 31, 1999. Under the terms of the agreement the Company was paid when the average monthly price for crude oil on the NYMEX is below the floor price and will pay the counterparty when the average monthly price exceeds the ceiling price. During the nine months ended September 30, 1999 the Company realized a gain of $204,000 on this agreement, which is accounted for in crude oil and natural gas revenue. The Company has also entered into a hedge agreement with Barrett Resources Corporation ("Barrett") covering 2,000 Bbls per day of crude oil calling for the Company to realize an average NYMEX price of $14.23 per Bbl over the period April 1, 1999 to October 31, 1999. In May 1999, the Company and Barrett amended this hedge agreement resulting in the Company being paid an average NYMEX price of $17.00 per Bbl from June through October 1999. A new agreement was entered into in October of 1999 for the period November 1999 through October 2000. This agreement is for 1,000 Bbls per day with the Company being paid $20.30 and 1,000 barrels per day with a floor price of $18.00 per barrel and a ceiling of $22.00 per Bbl. Additionally, Barrett has a 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 through October 31, 2002. The Company realized a loss of $0.9 million on this agreement which is accounted for in crude oil and natural gas revenue during the nine months ended September 30, 1999. As of March 1, 1999, the Company had 37.0 MMBtupd hedged at an average NYMEX price of approximately $1.93 per MMBtu from April 1, 1999 to October 31, 1999 and 2.4 MMBtuUpd at an average NYMEX price of approximately $1.10 per MMBtu from November 1, 1998 to October 31, 2000. Of the 37.0 MMBtupd hedged at $1.93 per MMBtu, 20.0 MMBtupd hedged with Barrett Resources Corporation, 11.0 MMBtupd is hedged with Engage Energy Capital Canada LP, and 6.0 MMBtupd is hedged with Amoco. New agreements were entered into for the term November 1, 1999 through October 31, 2000 with Barrett Resources. The new agreement is for 20.0 MMBtupd with a ceiling of $2.39 and a floor of $2.07 based on an AECO index. Barrett Resources has an option to extend the agreement through October 2002 at fixed prices. The 2.4 MMBtupd hedged at $1.10 per MMBtu is hedged with Barrett and was assumed by the Company in connection with the acquisition of New Cache. In connection with the 20.0 MMBtuTU Barrett hedge, the Company realized a loss of $1.8 million for the nine months ended September 30, 1999, which is accounted for in crude oil and natural gas revenue. Net Operating Loss Carryforwards. At December 31, 1998, the Company had, subject to the limitations discussed below, $59.2 million of net operating loss carryforwards for U.S. tax purposes, of which approximately $55.0 million are available for utilization without limitation. These loss carryforwards will expire from 1999 through 2019 if not utilized. At December 31, 1998, the Company had approximately $11.9 million of net operating loss carryforwards for Canadian tax purposes which expire in varying amounts in 2002-2005. 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 $4.9 million in net operating loss carryforwards generated prior to December 31, 1991 will be limited to approximately $235,000 per year. As a result of the issuance of additional shares of common stock for acquisitions and sales of 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, or $8.9 million, will be limited to approximately $1 million per year subject to the lower limitations described above. Of the $8.9 million net operating loss carryforwards, it is anticipated that the maximum net operating loss that may be utilized before it expires is $6.1 million. Future changes in ownership may further limit the use of the Company's carryforwards. 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 $5.9 million and $32.8 million for deferred tax assets at December 31, 1997 and 1998, respectively. Based upon the current level of operations, the Company believes that cash on hand, cash flow from operations, proceeds from the Production Payment, reduced interest expense as a result of the proposed restructuring and proceeds from the sale of non-core assets will be adequate to meet its anticipated requirements for working capital, capital expenditures and scheduled interest payments through 1999. Depressed prices for natural gas, crude oil or natural gas liquids will have a material adverse effect on the Company's cash flow from operations and anticipated levels of working capital, and could force the Company to revise its planned capital expenditures. 9 Year 2000 The Company has assessed the impact of the Year 2000 issue on its operations, including the development and implementation of project plans and cost estimates required to make its information system infrastructure, information systems and embedded technology Year 2000 compliant. Substantially all of the Company's computer hardware and software has been obtained from third party vendors. The Company has been advised by the vendors of each of its most material hardware and software systems that such systems are Year 2000 compliant. The Company has performed independent testing of critical applications to verify the accuracy of such assertions. The Company believes that all of its information system infrastructure, information systems and embedded technology are compliant and Year 2000 ready. In the area of third party suppliers and customers, the Company has monitored and assessed the readiness of such third parties. The Company monitors third party readiness based on correspondence received from its major vendors and suppliers, review of Year 2000 disclosure in documents filed with the SEC and verbal communications. The Company has not identified any material problems associated with the Year 2000 readiness efforts of its major suppliers and customers and, other than correspondence, documents filed with the SEC and verbal communications, the Company has not received any assurances that such customers and suppliers will be Year 2000 compliant. The Company's current emphasis in this area is focused on contingency planning in recognition of the uncertainties inherent in evaluating third party readiness. The Company's contingency planning involves all areas of readiness. The process includes identifying critical dependencies and developing proactive prevention plans. To date, the Company has spent approximately $120,000 in replacing computer hardware and software it did not believe to be Year 2000 compliant, some of which the Company had already anticipated replacing for other reasons. Such expenditures have been funded out of the Company's operational cash flows. Based on existing information, the Company does not anticipate having to spend any further material amounts to become Year 2000 compliant and that any such required amounts will not have a material effect on the financial position, cash flows or results of operations of the Company. There is a risk of Year 2000 related failures. These failures could result in an interruption in or a failure of certain business activities or functions. Such failures could materially and adversely affect the Company's results of operations, liquidity or financial condition. Due to the uncertainty surrounding the Year 2000 problem, including the uncertainty of the Year 2000 readiness of the Company's customers and suppliers, the Company is unable at this time to determine the true impact of the Year 2000 problem to the Company. The principal areas of risk are thought to be oil and gas production control systems, other imbedded operations control systems and third party Year 2000 readiness. There can be no assurance, however, that there will not be delay in, or increased costs associated with the implementation of measures to address the Year 2000 issue or that such measures will prove effective in resolving all Year 2000 related issues. Furthermore, there can be no assurance that critical contractors, customers or other parties with which the Company does business will not experience failures The Company believes that the "most reasonably likely worst case" scenarios are as follows: (i) unanticipated Year 2000 induced failures in information systems could cause a reliance on manual contingency procedures and significantly reduce efficiencies in the performance of certain normal business activities; (ii) unanticipated failures in embedded operations process control systems due to Year 2000 causes could result in temporarily suspending operations at certain operating facilities with consequent loss of revenue; and (iii) slowdowns or disruptions in the third party supply chain due to Year 2000 causes could result in operational delays and reduced efficiencies in the performance of certain normal business activities. 10 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: December 14, 1999 By:/s/_______________________ ROBERT L.G. WATSON, President and Chief Executive Officer Date: December 14, 1999 By:/s/________________________ CHRIS WILLIFORD, Executive Vice President and Principal Accounting Officer 11 -----END PRIVACY-ENHANCED MESSAGE-----