-----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, QCeZrA3T398fz2TIQF2eZtoX6hAyjY5SKB84q5yHs4EyU2TKDuNR+4uQfkAgSddw YQdfgrCoyNb3MPCI986uZA== 0000867665-02-000005.txt : 20020415 0000867665-02-000005.hdr.sgml : 20020415 ACCESSION NUMBER: 0000867665-02-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020405 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-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-16071 FILM NUMBER: 02602734 BUSINESS ADDRESS: STREET 1: 500 N LOOP 1604 E STE 100 CITY: SAN ANTONIO STATE: TX ZIP: 78232 BUSINESS PHONE: 2104904788 MAIL ADDRESS: STREET 1: 500 N LOOP 1604 EAST STE 100 CITY: SAN ANTONIO STATE: TX ZIP: 78232 10-K 1 abp10k2001.txt SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2001 [ ]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 Identification Number) Incorporation or Organization) 500 N. Loop 1604 East, Suite 100 San Antonio, Texas 78232 (Address of principal executive offices) Registrant's telephone number, including area code (210) 490-4788 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Common Stock, par value $.01 per share SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None 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 for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] The aggregate market value of the voting stock (which consists solely of shares of common stock) held by non-affiliates of the registrant as of March 22, 2002, based upon the closing per share price of $1.44, was approximately $39,005,914 on such date. The number of shares of the issuer's common stock, par value $.01 per share, outstanding as of March 22, 2002 was 29,979,397 shares of which 27,087,440 shares were held by non-affiliates. Documents Incorporated by Reference: Portions of the registrant's Proxy Statement relating to the 2002 Annual Meeting of Shareholders to be held on May 24, 2002 have been incorporated by reference herein (Part III).
ABRAXAS PETROLEUM CORPORATION FORM 10-K TABLE OF CONTENTS PART I Page Item 1. Business. .....................................................................................4 General.......................................................................................4 Recent Events.................................................................................5 Business Strategy ............................................................................6 Markets and Customers.........................................................................7 Risk Factors..................................................................................8 Regulation of Crude Oil and Natural Gas Activities...........................................19 Canadian Royalty Matters.....................................................................22 Environmental Matters ......................................................................23 Title to properties..........................................................................25 Employees....................................................................................25 Item 2. Properties....................................................................................25 Primary Operating Areas......................................................................25 Exploratory and Developmental Acreage........................................................26 Productive Wells.............................................................................26 Reserves Information.........................................................................27 Crude Oil, Natural Gas Liquids and Natural Gas Production and Sales Price ...................23 Drilling Activities..........................................................................29 Office Facilities............................................................................30 Other Properties.............................................................................30 Item 3. Legal Proceedings.............................................................................30 Item 4. Submission of Matters to a Vote of Security Holders...........................................31 Item 4a.Executive Officers of Abraxas..................................................................31 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters............................................................32 Market Information...........................................................................32 Holders......................................................................................32 Dividends....................................................................................32 Item 6. Selected Financial Data.......................................................................33 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................................33 General......................................................................................33 Results of Operations........................................................................33 Liquidity and Capital Resources..............................................................39 Critical Accounting Policies................................................................49 New Accounting Pronouncements...............................................................50 Item 7a. Quantitative and Qualitative Disclosures about Market Risk....................................50 Item 8. Financial Statements and Supplementary Data...................................................51 2 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................................................52 PART III Item 10. Directors and Executive Officers of the Registrant .........................................52 Item 11. Executive Compensation.......................................................................52 Item 12. Security Ownership of Certain Beneficial Owners and Management...............................52 Item 13. Certain Relationships and Related Transactions...............................................52 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...................................................................52 SIGNATURES..................................................................................57
3 FORWARD-LOOKING INFORMATION We make forward-looking statements throughout this document. Whenever you read a statement that is not simply a statement of historical fact (such as when we describe what we "believe," "expect" or "anticipate" will occur, and other similar statements), you must remember that our expectations may not be correct, even though we believe they are reasonable. The forward-looking information contained in this annual report is generally located in the material set forth under the headings "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business," but may be found in other locations as well. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management's reasonable estimates of future results or trends. The factors that may affect our expectations of our operations include, among others, the following: o Our high debt level o Our ability to raise capital o Economic and business conditions o Our success in completing acquisitions or in development and exploration activities o Prices for crude oil and natural gas; and o Other factors discussed elsewhere in this document PART I Item 1. Business General Abraxas Petroleum Corporation ("Abraxas" or the "Company") is an independent energy company engaged primarily in the acquisition, exploration, exploitation and production of crude oil and natural gas. Since January 1, 1991, our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties and related assets. As a result of our historical acquisition activities, we believe we have a substantial inventory of low risk exploration and development opportunities, the development of which is critical to the maintenance and growth of our current production levels. We seek to complement our acquisition and development activities by selectively participating in exploration projects with experienced industry partners. Since December 31, 2001 an improving price environment related to crude oil and natural gas, recent drilling success of the Company and anticipated property sales, all discussed below as "Recent Events", are important factors in evaluation of the Company's prospects going forward. Our principal areas of operation are Texas and western Canada. At December 31, 2001, we owned interests in 937,149 gross acres (636,516 net acres) and operated properties accounting for 76% of our PV-10, affording us substantial control over the timing and incurrence of operating and capital expenditures. At December 31, 2001, estimated total proved reserves of Abraxas (U.S. operations) and our wholly-owned subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian Abraxas") and Grey Wolf Exploration, Inc. ("Grey Wolf") were 229.6 Bcfe with an aggregate PV-10 of $209.7 million. As of December 31, 2001, we had net natural gas processing capacity of 107 MMcf per day through our various ownership interests in 12 natural gas processing plants and compression facilities in Canada, giving us substantial control over our Canadian production and marketing activities. PV-10 means estimated future net revenue discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the Securities and Exchange Commission. A Mcf is one thousand cubic feet of natural gas. MMcf is used to designate one million cubic feet of natural gas and Bcf refers to one billion cubic feet of natural gas. Mcfe means thousands of cubic feet of natural gas equivalents, using a conversion ratio of one barrel of crude oil to six Mcf of natural gas. MMcfe means millions of cubic feet of natural gas equivalents and Bcfe means billions of cubic feet of natural gas equivalents. Mmbtu means million British Thermal Units. The term Bbl means one barrel of crude oil and MBbls is used to designate one thousand barrels of crude oil or natural gas liquids. 4 In accordance with the Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the Company's financial statements. As of December 31, 2001, the Company's net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, crude oil and natural gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved crude oil and natural gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural gas. The Company also used the subsequent prices to evaluate its Canadian properties, and reduced the 2001 year-end write-down to an amount of $2.6 million on those properties. Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor. We currently have significant interest payments due in 2002 of $30.2 million and principal obligations payable in 2003 ($63.5 million) and 2004 ($191.0 million). Our debt service requirements may restrict our ability to fund capital expenditures necessary to maximize the value of our assets. The debt levels also restrict our ability to borrow additional amounts to fund asset growth or to provide financial flexibility. Additionally, our ability to meet our debt obligations and to reduce our level of debt depends on our future performance and crude oil and natural gas production and commodity prices. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. If we are unable to make interest payments on our debt or to repay our debt at maturity out of cash on hand, we could attempt to refinance such debt, or repay such debt with the proceeds of the sale of certain producing properties or an equity offering. The use of the sale proceeds from a property sale are substantially limited by the terms of the indentures governing our indebtedness. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our value and performance at the time of such offering or other financing. We cannot assure you that any property sale, offering or refinancing can be successfully completed. Recent Events Potential Property Sales Our wholly owned Canadian subsidiaries, Grey Wolf and Canadian Abraxas, have 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. If all of the potential sales are ultimately closed, we anticipate aggregate proceeds in the range of $50 million to $100 million. 5 Lady Fern Drilling Our wholly-owned Canadian subsidiary, Grey Wolf has drilled four wells of a six well program in the Lady Fern area of Northeast British Columbia during this winter drilling season. Two of the wells in which we own a 16.66% interest in each well have indicated some success and are being completed and production tested. Two wells were dry holes. The final two wells of the program are currently drilling. Improved Commodity Prices Since December 31, 2001, commodity prices have improved significantly. As a point of reference, on March 22, 2002, the NYMEX natural gas price was $3.43 per Mcf, and the NYMEX crude oil price was $25.35 per Bbl as compared to December 31, 2001 natural gas price of $2.57 per Mcf and crude oil price of $19.84 per Bbl. The improvement in prices since December 31, 2001, has limited our potential impairment write down of crude oil and natural gas properties at year end 2001 and if such prices are sustained, should improve our liquidity and cash flows. For a more detailed description of commodity prices, you should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations." Business Strategy Our primary business objectives are to increase reserves, production and cash flow through the following: o Improved Liquidity. In recent 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. o We are continuing to rationalize our Canadian assets to allow us to continue to grow while reducing our debt. Our wholly owned Canadian subsidiaries, Canadian Abraxas and Grey Wolf have 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 may sell additional assets or seek partners to fund a portion of the exploration costs of undeveloped acreage, and we are considering other potential strategic alternatives. We have recently engaged Randall & Dewey to explore a potential sale of certain of our properties located in Texas. 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. If all of the potential sales are ultimately closed, we anticipate proceeds in the range of $50 million to $100 million. See "Recent Events". o Our sale in March 1999 of 12.875% Senior Secured Notes due 2003 (the "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. o 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 South Texas to Mirant Americas. We have the ability to sell up to $50 million of production payments to Mirant Americas for drilling opportunities in South Texas . o 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. o In March 2000, we sold our interest in certain crude oil and natural gas properties that we owned and operated in Wyoming. Simultaneously, a 6 limited partnership of which one of our subsidiaries was the general partner, which we 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. o 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 through drilling activities. o In December 2001, Grey Wolf entered into a financing agreement with Mirant Canada Energy Capital, Ltd. for CDN $150 million (approximately US $96 million) (the "Grey Wolf Facility"), 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. o Low Cost Operations. We seek to maintain low lease operating and G&A expenses per Mcfe by operating a majority of our producing properties and related assets and by maintaining a high rate of production on a per well basis. As a result of this strategy, we have achieved per unit operating and G&A expenses that compare favorably with similar companies. o Exploitation of Existing Properties. We will allocate a portion of our operating cash flow to the exploitation of our producing properties. We believe that the proximity of our undeveloped reserves to existing production makes development of these properties less risky and more cost-effective than other drilling opportunities available to us. 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 2002 for existing operations and leaseholds is approximately $37 million. o Producing Property Acquisitions. As cash flow permits, we intend to continue to acquire producing crude oil and natural gas properties that can increase cash flow, production and reserves through operational improvements and additional development. o Focused Exploration Activity. We may allocate a portion of our capital budget to the drilling of exploratory wells that have high reserve potential. We believe that by devoting a relatively small amount of capital to high impact, high risk projects while reserving the majority of our available capital for development projects, we can reduce drilling risks while still benefiting from the potential for significant reserve additions. Markets and Customers The revenue generated by our operations is highly dependent upon the prices of, and demand for, crude oil and natural gas. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our crude oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation and policies. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenue, profitability and cash flow from operations. You should read the discussion under "Risk Factors - Crude oil and natural gas prices and their volatility could adversely our revenues, cash flows and profitability." and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies" for more information relating to the effects on us of decreases in crude oil and natural gas prices. In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, from time to time we have entered into fixed price delivery contracts, financial swaps and crude oil and natural gas futures contracts as 7 hedging devices. To ensure a fixed price for future production, we may sell a futures contract and thereafter either (i) make physical delivery of crude oil or natural gas to comply with such contract or (ii) buy a matching futures contract to unwind our futures position and sell our production to a customer. These contracts may expose us to the risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase or deliver the contracted quantities of crude oil or natural gas, or a sudden, unexpected event materially impacts crude oil or natural gas prices. These contracts may also restrict our ability to benefit from unexpected increases in crude oil and natural gas prices. You should read the discussion under "Management's Discussion and Analysis of Financial Condition And Results of Operations -- Liquidity and Capital Resources," and "Quantitative and Qualitative Disclosures about Market Risk; Commodity Price Risk" for more information regarding our hedging activities. Substantially all of our crude oil and natural gas is sold at current market prices under short-term contracts, as is customary in the industry. During the year ended December 31, 2001, three purchasers accounted for approximately 41% of our crude oil and natural gas sales. We believe that there are numerous other companies available to purchase our crude oil and natural gas and that the loss of one or more of these purchasers would not materially affect our ability to sell crude oil and natural gas. The prices we receive for the sale of our crude oil and natural gas are subject to our hedging activities. You should read the discussion under "Management's Discussion and Analysis of Financial Condition And Results of Operations -- Liquidity and Capital Resources" and "Quantitative and Qualitative Disclosures about Market Risk; Commodity Price Risk" for more information regarding our hedging activities. Risk Factors We lack financial liquidity due to our reduced cash flow. We have historically funded our operations and capital expenditures primarily through cash flow from operations, sales of properties and sales of production payments to Mirant Americas and other credit sources. We anticipate that we will have four principal sources of liquidity during the next 12 months: (i) cash on hand, (ii) cash generated by operations, (iii) sales of production payments to Mirant Americas, and (iv) sales of properties. In addition, Grey Wolf has additional borrowing capacity under its credit facility with Mirant Canada to fund Grey Wolf's drilling activities. Our cash flow from operations has been severely impacted by depressed commodity prices since the third quarter of 2001. While commodity prices have recently increased, we cannot assure you that these price levels can be sustained. The reduced cash flow from operations has also reduced the overall volume of crude oil and natural gas that we can produce economically and increased our dependence on external sources of capital to fund our operations and capital expenditures. In addition, we have been unable to replace the production represented by the properties that we have sold with new production from the producing properties we drilled with the proceeds of our property sales. Our ability to raise funds through additional indebtedness will be substantially limited by the terms of the indentures governing our outstanding First Lien Notes and Second Lien Notes. We may also choose to issue equity securities or sell certain of our properties to fund our operations and capital expenditures, although the indentures substantially limit our use of the proceeds of any such asset sales. You should read the discussions under the headings "Our debt levels and our debt covenants may limit our ability to pursue business opportunities and to obtain additional financing," "We may issue shares of our preferred stock with greater rights than our common stock," "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources," and the Consolidated Financial Statements and the notes thereto included elsewhere for more information regarding our lack of liquidity. Our substantial losses have put significant strain on our liquidity and cash position. At December 31, 2001, we had cash of $7.6 million. We are currently managing our cash position through the reduction of our 2002 capital expenditures budget and other cost reduction efforts. However, while these measures will help conserve our cash resources in the near term, they will also limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations and results of operations in the future. For more information, you should read "Our ability to replace production with new reserves is highly dependent on acquisitions or successful development and exploration activities." In addition, we are actively seeking potential transactions for the sale of producing properties in order to increase our liquidity. Our failure to achieve revenue goals or the disposition of producing 8 properties on favorable terms during 2002 and beyond will have a significant adverse impact on the liquidity of the Company, and could possibly result in insolvency. Our debt levels and our debt covenants may limit our ability to pursue business opportunities and to obtain additional financing. We have substantial indebtedness and debt service requirements. Our total debt and stockholders' deficit were $285.6 million and $28.5 million, respectively, as of December 31, 2001. We may incur additional indebtedness in the future in connection with acquiring, developing and exploiting producing properties, although our ability to incur additional indebtedness is substantially limited by the terms of the indentures. You should read the discussions under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and the Consolidated Financial Statements and the notes thereto included elsewhere in this annual report for more information regarding our indebtedness. Our high level of debt affects our operations in several important ways, including: o A substantial amount of our cash flow from operations will be used to pay interest on the First Lien Notes, any outstanding Old Notes and the Second Lien Notes and is not available for other purposes including developing our producing properties; o The covenants contained in the First Lien Notes indenture and the Second Lien Notes indenture limit our ability to borrow additional funds or to dispose of assets and may affect our flexibility in planning for, and reacting to, changes in our business, including limiting acquisition activities; o Our debt level may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, interest payments, scheduled principal payments, general corporate purposes or other purposes; and o The terms of the First Lien Notes indenture, the Old Notes indenture and the Second Lien Notes indenture will permit the holders of the First Lien Notes, any outstanding Old Notes and the Second Lien Notes to accelerate payments upon an event of default or a change of control. Our high level of debt increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance which, in turn, depends on general economic conditions and financial, business and other factors, many of which are beyond our control. If we are unable to generate cash flow from operations to service the First Lien Notes, the Second Lien Notes and the Old Notes, we may be required to refinance all or a portion of our debt or obtain additional financing. Our ability to refinance all or a portion of our debt or to obtain additional financing is substantially limited by the terms of the indentures. Factors that will affect our ability to raise cash in a financing include our financial condition and our value and performance at the time of any offering or other financing. We also continue to explore the sale of properties; however, the indentures substantially limit our ability to use the proceeds of any such sale. We cannot assure you that we will be successful in any refinancing, offering or property sale. We have substantial capital requirements. 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. In 2001, we met our liquidity needs through cash flow from operations, the sale of additional properties and further installments on the production payment with Mirant Americas. We are examining certain alternative sources of long term capital including: o refinancing or recapitalizing our current indebtedness; o selling equity securities; and o selling additional properties. 9 The availability of these sources of capital depend upon a number of factors, many of which are beyond our control such as general economic and financial market conditions and crude oil and natural gas prices. Further, our cash flow from operations could be negatively affected by our limited ability, due to our limited liquidity, to acquire producing properties, to undertake exploration and development projects and to otherwise replenish our depleting reserves. Our ability to raise funds through additional indebtedness will be substantially limited by the terms of the indenture governing the First Lien Notes, the indenture governing the Old Notes and the indenture governing the Second Lien Notes, although many of the restrictive covenants contained in the indenture governing the Old Notes were eliminated in connection with the Exchange Offer. 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. Additionally, 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 substantial restrictions on the use of proceeds from asset sales. While there can be no assurances, we believe that our improved cash flow from operations due to successful development activities, the sale of properties and additional installments on the production payment with Mirant Americas will provide us with sufficient capital for the next 12 months. However, if our production or commodity prices decrease or if our drilling activities cost more than we anticipate, we may not be able to execute our business plan without additional capital. The collateral securing the First Lien Notes and the Second Lien Notes may not be adequate. The First Lien Notes and the related guarantees are secured by a first lien or charge on substantially all of the crude oil and natural gas properties and natural gas processing facilities of Abraxas and the guarantors, Canadian Abraxas, Sandia Oil and Gas Corp. ("Sandia") and Wamsutter Holdings, Inc. ("Wamsutter"), as well as the shares of Grey Wolf common stock owned by Abraxas and Canadian Abraxas (collectively, the "Collateral"), including crude oil and natural gas properties with a PV-10 of $158.3 million at December 31, 2001. The Second Lien Notes and the related guarantees are secured by a second lien or charge on the Collateral. The crude oil and natural gas properties of Grey Wolf, which had a PV-10 of $51.4 million at December 31, 2001, are not collateral for the First Lien Notes or the Second Lien Notes. These properties secure Grey Wolf's obligations under the Grey Wolf Facility. The reserve data with respect to such interests, however, represent estimates only and should not be construed as exact. Moreover, the PV-10 estimates should not be construed as the current market value of the estimated proved reserves attributable to our properties. You should read the discussions under the heading "Estimates of Proved Reserves and Future Net Revenue Are Uncertain and Inherently Imprecise" and "Properties -- Reserves Information" for more information regarding our reserves. We cannot assure you that if an event of default occurs that the liquidation of the Collateral would produce proceeds sufficient to pay all of our obligations under the First Lien Notes and the Second Lien Notes. Fraudulent conveyance laws could allow a court to void the guarantees. Abraxas' subsidiaries Canadian Abraxas, Wamsutter and Sandia are guarantors under the First Lien Notes, and Canadian Abraxas is jointly and severally liable with Abraxas and Wamsutter and Sandia are guarantors under the Second Lien Notes. Under the federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee could be voided, or claims in respect of a 10 guarantee could be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee: o received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee; and o was insolvent or rendered insolvent by reason of such incurrence; or o was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or o intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature. In addition, any payment by that guarantor pursuant to its guarantee could be voided and required to be returned to the guarantor, or to a fund for the benefit of the creditors of the guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if: o the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets, or o if the present fair saleable value of its assets were less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature, or o it could not pay its debts as they become due. We believe that Abraxas, Canadian Abraxas, Sandia and Wamsutter received reasonably equivalent value at the time they incurred the indebtedness under the First Lien Notes, the Second Lien Notes or related guarantees, as applicable, and granted the security interests in the Collateral securing the First Lien Notes, the Second Lien Notes and the related guarantees. In addition, Abraxas, Canadian Abraxas, Sandia and Wamsutter believe that none of them were, at the time of or as a result of the issuance of the First Lien Notes, the Second Lien Notes or the related guarantees and the granting of the security interests in the Collateral securing the First Lien Notes, the Second Lien Notes and the related guarantees, insolvent under the foregoing standards, that none of Abraxas, Canadian Abraxas, Sandia or Wamsutter will be engaged in a business or transaction for which its remaining assets constitute unreasonably small capital and that none of them intends or will intend to incur debts beyond its ability to pay such debts as they mature. These beliefs are based upon management's analysis of internal cash flow projections and estimated values of assets and liabilities of Abraxas, Canadian Abraxas, Sandia and Wamsutter. We cannot assure you, however, that a court passing on such questions would agree with Abraxas. Under applicable provisions of Canadian federal bankruptcy law or comparable provisions of provincial fraudulent preference laws, if a court in an action brought by an unpaid creditor of Canadian Abraxas or by a bankruptcy trustee of Canadian Abraxas were to find that the liens granted by Canadian Abraxas over its assets were intended to prefer the holders of the First Lien Notes and the Second Lien Notes over other creditors, such liens could be set aside. This would become an issue if Canadian Abraxas became insolvent or bankrupt within a certain period after granting the liens. However, to the extent that the grant of security is to secure new loan advances, there would be no fraudulent preference under Canadian bankruptcy or fraudulent preference laws. Bankruptcy laws could impair your rights. In the event Abraxas or any of the guarantors were to become a debtor subject to insolvency proceedings under the United States Bankruptcy Code ("Bankruptcy Code"), Canadian Federal bankruptcy law or general state or provincial laws (to the extent not superseded by respective federal laws), it is likely delays may occur in payment of the First Lien Notes and the Second Lien Notes and in enforcing remedies under the First Lien Notes and the Second Lien Notes, any guarantee or the liens securing the First Lien Notes and the Second Lien Notes and the guarantees because of specific provisions of such laws or by a court applying general principles of 11 equity. Provisions under the Bankruptcy Code or general principles of equity that could result in the impairment of your rights include, but are not limited to: o an automatic stay, o avoidance of preferential transfers by a trustee or debtor-in-possession, o substantive consolidation, o limitations on collectability of unmatured interest or attorney fees and forced restructuring of the First Lien Notes or the Second Lien Notes. There are similar provisions under Canadian law. Under the Bankruptcy Code, a trustee or debtor-in-possession may generally recover payments or transfers of property of a debtor if such payment or transfer was: o to or for the benefit of a creditor, o in payment of an antecedent debt owed before the transfer was made, o made while the debtor was insolvent, o within ninety (90) days (or one year if the payment was to an "insider" of the debtor) before the filing of the bankruptcy case that enabled the creditor to receive more than it would have received in a liquidation under Chapter 7 of the Bankruptcy Code, the transfer had not been made and the creditor received payment of the debt as provided in the Bankruptcy Code. As an example, if payments were made on the First Lien Notes or the Second Lien Notes prior to the filing of a bankruptcy case and a court subsequently determined that the value of the collateral pledged by the entity making the payment was less than the debt owed, such payments could be subject to avoidance as a preferential transfer. Our financial failure could also result in impairment of payment of the First Lien Notes or the Second Lien Notes if a bankruptcy court were to "substantially consolidate" Abraxas and its subsidiaries. If a bankruptcy court substantially consolidated Abraxas and its subsidiaries, the assets of each entity would be subject to the claims of creditors for all entities. Such a consolidation would expose the holders of the First Lien Notes or the Second Lien Notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Forced restructuring of the First Lien Notes or the Second Lien Notes could occur through the "cram-down" provision of the Bankruptcy Code. Under this provision, the First Lien Notes or the Second Lien Notes could be restructured over objections of holders of the First Lien Notes or the Second Lien Notes as to their general terms, primarily interest rate and maturity. Additionally, the First Lien Notes or the Second Lien Notes could be bifurcated into a secured debt and unsecured debt if a bankruptcy court were to find that the debt owed by Abraxas exceeded the value of the collateral. If this were to occur, the unsecured portion of the debt could be afforded different treatment than the secured portion of the debt, including the disallowance of the accrual of post petition interest on the First Lien Notes or the Second Lien Notes. Additionally, due to Abraxas and the guarantors being domiciled in Canada and in the United States, Abraxas and the guarantors could be subject to multi-jurisdictional insolvency proceedings in Canada and the United States. If multi-jurisdictional insolvency proceedings were to occur, this could result in additional delay in payment of the First Lien Notes or the Second Lien Notes, as well as delay in or prevention from enforcing remedies under the First Lien Notes or the Second Lien Notes, any guarantee and the liens securing the First Lien Notes or the Second Lien Notes and the guarantees. Likewise, the First Lien Notes or the Second Lien Notes could be subject to different treatment inasmuch as the multiple insolvency proceedings would be conducted by different courts applying different laws. Crude oil and natural gas prices and their volatility could adversely affect our revenue, cash flows and profitability. Our revenue, profitability and future rate of growth depend substantially upon prevailing prices for crude oil and natural gas. Natural gas prices affect us more than crude oil prices since most of our production and reserves are natural gas. Prices also affect the amount of 12 cash flow available for capital expenditures and our ability to borrow money or raise additional capital. For example, in 1999 we reduced our capital expenditures budget because of lower crude oil and natural gas prices. In addition, we may have ceiling test write-downs when prices decline. Lower prices may also reduce the amount of crude oil and natural gas that we can produce economically. We cannot predict future crude oil and natural gas prices. Factors that can cause price fluctuations include: o changes in supply and demand for crude oil and natural gas; o weather conditions; o the price and availability of alternative fuels; o political and economic conditions in oil producing countries, especially those in the Mideast; and o overall economic conditions. In addition to decreasing our revenue and cash flow from operations, low or declining crude oil and natural gas prices could have additional material adverse effects on us, such as: o reducing the overall volumes of crude oil and natural gas that we can produce economically; o cause a ceiling limitation write-down; o increase our dependence on external sources of capital to meet our liquidity requirements; and o impair our ability to obtain needed equity capital. Hedging transactions may limit our potential gains. We have entered into hedge agreements and other financial arrangements at various times to attempt to minimize the effect of crude oil and natural gas price fluctuations. We cannot assure you that such transactions will reduce risk or minimize the effect of any decline in crude oil or natural gas prices. Any substantial or extended decline in crude oil or natural gas prices would have a material adverse effect on our business and financial results. Hedging activities may limit the risk of declines in prices, but such arrangements may also limit additional revenues from price increases. In addition, such transactions may expose us to risks of financial loss under certain circumstances, such as: o production is less than expected; or o price differences between delivery points for our production and those in our hedging agreements increase. In 2000 and 2001, we experienced hedging losses of $20.2 million and $12.1 million, respectively. At year end 2001, the fair value of future hedges was a liability of approximately $658,000, which we believe will reduce our cash flow from operations in 2002. Our hedge agreements expire in October 2002. To the extent that these hedge agreements require us to pay the counterparty, our revenue will be reduced. You should read the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Liquidity and Capital Resources - Hedging Activities" for more information regarding our hedging activities. Lower crude oil and natural gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for our crude oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down". This charge does not impact cash flow from 13 operating activities, but does reduce our stockholders' equity and earnings. The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for our natural gas production. As of December 31, 2001, the Company's net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, crude oil and natural gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved crude oil and natural gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural gas. The Company also used the subsequent prices to evaluate its Canadian properties, and reduced the 2001 year-end write-down to an amount of $2.6 million on those properties. In 1999, we recorded a write-down of $19.1 million as a result of a downward adjustment to our proved reserves in Canada. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. For more information on the full cost method of accounting and ceiling limitation write-downs, you should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies." Estimates of our proved reserves and future net revenue are uncertain and inherently imprecise. This annual report contains estimates of our proved crude oil and natural gas reserves and the estimated future net revenue from such reserves. The process of estimating crude oil and natural gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise. Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control. You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor. The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the PV-10 thereof for the crude oil and natural gas properties described in this document are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 2001. The sales prices as of such date used for purposes of such estimates were $18.26 per Bbl of crude oil, $16.29 per Bbl of NGLs and $2.20 per Mcf of natural gas. This compares with $25.73 per Bbl of crude oil, $30.63 per Bbl of NGLs and $9.21 per Mcf of natural gas as of December 31, 2000. It is also assumed that we will make future capital expenditures of approximately $56.6 million in the aggregate, which are necessary to develop and realize the value of proved undeveloped reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein. 14 We have experienced recurring net losses. The following table shows the losses Abraxas had in 1997, 1998, 1999 and 2001: 1997 1998 1999 2001 ---------- -------------- ------------- ------------ (US $ in millions) ---------------------------------------------------- Net loss applicable to common stock......... $(6.5) $(84.0) $(36.7) $(19.7) ========== ============== ============= ============ While Abraxas had net income in 2000 of $8.4 million, if the significant gain on the sale of an interest in a partnership were excluded, Abraxas would have experienced a net loss for the year of $(25.5) million. Abraxas cannot assure you that it will become profitable in the future. You should read the discussions under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our Consolidated Financial Statements and the notes thereto included elsewhere in this document for more information regarding these losses. Our ability to replace production with new reserves is highly dependent on acquisitions or successful development and exploration activities. The rate of production from crude oil and natural gas properties declines as reserves are depleted. Our proved reserves will decline as reserves are produced unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. Our future crude oil and natural gas production is therefore highly dependent upon our level of success in acquiring or finding additional reserves. We cannot assure you that our exploration and development activities will result in increases in reserves. Our operations may be curtailed, delayed or cancelled if we lack necessary capital and by other factors, such as title problems, weather, compliance with governmental regulations, mechanical problems or shortages or delays in the delivery of equipment. Our ability to acquire or find additional reserves will be severely diminished by our lack of available funds for acquisition, exploration and development projects. We have implemented a number of measures to conserve our cash resources, including postponement of exploration and development projects. However, while these measures will conserve our cash resources in the near term, they will also limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations in the future. Our ability to continue to acquire producing properties or companies that own such properties assumes that major integrated oil companies and independent oil companies will continue to divest many of their crude oil and natural gas properties. We cannot assure you that such divestitures will continue or that we will be able to acquire such properties at acceptable prices or develop additional reserves in the future. In addition, under the terms of the First Lien Notes indenture, the Old Notes indenture and the Second Lien Notes indenture, our ability to obtain additional financing in the future for acquisitions and capital expenditures will be limited. Our operations are subject to numerous risks of crude oil and natural gas drilling and production activities. Crude oil and natural gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the following: o that no commercially productive crude oil or natural gas reservoirs will be found; o that crude oil and natural gas drilling and production activities may be shortened, delayed or canceled; and o that our ability to develop, produce and market our reserves may be limited by: - title problems, - weather conditions, - compliance with governmental requirements, and - mechanical difficulties or shortages or delays in the delivery of drilling rigs, work boats and other equipment. In the past, we have had difficulty securing drilling equipment in certain of our core areas. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. 15 Drilling for crude oil and natural gas may be unprofitable. Dry holes and wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable. In addition, our properties may be susceptible to hydrocarbon draining from production by other operations on adjacent properties. Our industry also experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. We operate in a highly competitive industry which may adversely affect our operations. We operate in a highly competitive environment. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of such undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase such properties, and the financial resources necessary to acquire and develop such properties. We compete with major and independent crude oil and natural gas companies for properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours. The principal resources necessary for the exploration and production of crude oil and natural gas are leasehold prospects under which crude oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We must compete for such resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future we cannot assure you that such materials and resources will be available to us. We face significant competition for obtaining additional natural gas supplies for gathering and processing operations, for marketing NGLs, residue gas, helium, condensate and sulfur, and for transporting natural gas and liquids. Our principal competitors include major integrated oil companies and their marketing affiliates and national and local gas gatherers, brokers, marketers and distributors of varying sizes, financial resources and experience. Certain competitors, such as major crude oil and natural gas companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas. We compete against other companies in our natural gas processing business both for supplies of natural gas and for customers to which we sell our products. Competition for natural gas supplies is based primarily on location of natural gas gathering facilities and natural gas gathering plants, operating efficiency and reliability and ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price and delivery capabilities. The marketability of our production depends largely upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. The marketability of our production depends in part upon processing facilities. Transportation space on such gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state and Canadian regulation of crude oil and natural gas production and transportation, general economic conditions, and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on us could be substantial and adversely affect our ability to produce and market crude oil and natural gas. Our crude oil and natural gas operations are subject to various U.S. federal, state and local and Canadian federal and provincial governmental 16 regulations that materially affect our operations. Matters regulated include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of crude oil and natural gas, these agencies have restricted the rates of flow of crude oil and natural gas wells below actual production capacity. Federal, state, provincial and local laws regulate production, handling, storage, transportation and disposal of crude oil and natural gas, by-products from crude oil and natural gas and other substances and materials produced or used in connection with crude oil and natural gas operations. To date, our expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant. We believe that we are in substantial compliance with all applicable laws and regulations. However, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. Our Canadian operations are subject to the risks of currency fluctuations and in some instances economic and political developments. We have significant operations in Canada. The expenses of such operations are payable in Canadian dollars while most of the revenue from crude oil and natural gas sales is based upon U.S. dollar price indices. As a result, Canadian operations are subject to the risk of fluctuations in the relative values of the Canadian and U.S. dollars. We are also required to recognize foreign currency translation gains or losses related to the debt issued by our Canadian subsidiary because the debt is denominated in U.S. dollars and the functional currency of such subsidiary is the Canadian dollar. Our foreign operations may also be adversely affected by local political and economic developments, royalty and tax increases and other foreign laws or policies, as well as U.S. policies affecting trade, taxation and investment in other countries. We depend on our key personnel. We depend to a large extent on Robert L.G. Watson, our Chairman of the Board, President and Chief Executive Officer, for our management and business and financial contacts. The unavailability of Mr. Watson could have a materially adverse effect on our business. Mr. Watson has a five-year employment contract with Abraxas, which provides that he can be terminated for cause only. Our success is also dependent upon our ability to employ and retain skilled technical personnel. While we have not experienced difficulties in employing or retaining such personnel, our failure to do so in the future could adversely affect our business. Shares eligible for future sale may depress our stock price. At March 22, 2002, we had 29,979,397 shares of common stock outstanding of which 2,891,957 shares were held by affiliates, 4,923,537 shares of common stock were subject to outstanding options granted under certain stock option plans (of which 2,834,457 shares were vested at March 22, 2002) and 950,000 shares were issuable upon exercise of warrants. All of the shares of common stock held by affiliates are restricted or control securities under Rule 144 promulgated under the Securities Act of 1933, as amended (the "Securities Act"). The shares of the common stock issuable upon exercise of the stock options have been registered under the Securities Act. The shares of the common stock issuable upon exercise of the warrants are subject to certain registration rights and, therefore, will be eligible for resale in the public market after a registration statement covering such shares has been declared effective. Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the common stock and could impair our ability to raise additional capital through the sale of equity securities. The price of Abraxas' common stock has been volatile and could continue to fluctuate substantially. Abraxas' common stock is traded on the American Stock Exchange ("AMEX"). The market price of Abraxas' common stock has been volatile and could fluctuate substantially based on a variety of factors, including the following: o fluctuations in commodity prices; o variations in results of operations; o legislative or regulatory changes; o general trends in the industry; 17 o market conditions; and o analysts' estimates and other events in the crude oil and natural gas industry. You should read the discussion under the heading "Market for Registrant's Common Equity and Related Stockholder Matters" for more information regarding the market price fluctuations of Abraxas' common stock. We may issue shares of preferred stock with greater rights than our common stock. Subject to the rules of the American Stock Exchange, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of our common stock. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common stock. Anti-takeover provisions could make a third party acquisition of Abraxas difficult. Abraxas' articles of incorporation and by-laws provide for a classified board of directors, with each member serving a three-year term and eliminate the ability of stockholders to call special meetings or take action by written consent. Abraxas has also adopted a stockholder rights plan. Each of the provisions in the articles of incorporation and by-laws and the stockholder rights plan could make it more difficult for a third party to acquire Abraxas without the approval of Abraxas' board. In addition, the Nevada corporate statute also contains certain provisions, which could make an acquisition by a third party more difficult. Use of our net operating loss carryforwards may be limited. 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 $34,763,000 and $39,670,000 for deferred tax assets at December 31, 2000 and 2001, respectively. 18 Regulation of Crude Oil and Natural Gas Activities The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our operations are affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, crude oil and natural gas production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental, and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations. Price Regulations In the past, maximum selling prices for certain categories of crude oil, natural gas, condensate and NGLs in the United States were subject to significant federal regulation. At the present time, however, all sales of our crude oil, natural gas, condensate and NGLs produced in the United States under private contracts may be sold at market prices. Congress could, however, reenact price controls in the future. If controls that limit prices to below market rates are instituted, the Company's revenue would be adversely affected. Crude oil and natural gas exported from Canada is subject to regulation by the National Energy Board ("NEB") and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB and the government of Canada. Crude oil and natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor in Council approval. The provincial governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from these provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and marketing considerations. The North American Free Trade Agreement On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of the United States, Canada and Mexico became effective. In the context of energy resources, Canada remains free to determine whether exports to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports. The Texas Railroad Commission has recently become the lead agency for Texas for coordinating permits governing Texas to Mexico cross border pipeline projects. The availability of selling natural gas into Mexico may substantially impact the interstate natural gas market on all producers in the coming years. United States Natural Gas Regulation Historically, the natural gas industry as a whole has been more heavily regulated than the crude oil or other liquid hydrocarbons market. Most regulations focused on transportation practices. In the recent past interstate pipeline companies in the United States generally acted as wholesale merchants by purchasing natural gas from producers and reselling the natural gas to local distribution companies and large end users. Commencing in late 1985, the Federal Energy Regulatory Commission (the "FERC") issued a series of orders that have had a major impact on interstate natural gas pipeline operations, services, and rates, and thus have significantly altered the marketing and price of natural gas. The FERC's key rule making action, Order No. 636 ("Order 636"), issued in April 1992, required each interstate pipeline to, among other things, "unbundle" 19 its traditional bundled sales services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and standby sales and natural gas balancing services), and to adopt a new ratemaking methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate markets natural gas as a merchant, it does so pursuant to private contracts in direct competition with all of the sellers, such as us; however, pipeline companies and their affiliates were not required to remain "merchants" of natural gas, and most of the interstate pipeline companies have become "transporters only," although many have affiliated marketers. Order 636 and related FERC orders have resulted in increased competition within all phases of the natural gas industry. We do not believe that Order 636 and the related restructuring proceedings affect us any differently than other natural gas producers and marketers with which we compete. Transportation pipeline availability and cost are major factors affecting the production and sale of natural gas. Our physical sales of natural gas are affected by the actual availability, terms and cost of pipeline transportation. The price and terms for access onto the pipeline transportation systems remain subject to extensive Federal regulation. Although Order 636 does not directly regulate our production and marketing activities, it does affect how buyers and sellers gain access to and use of the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines, although some appeals remain pending and the FERC continues to review and modify its regulations regarding the transportation of natural gas. For example, the FERC has recently begun a broad review of its natural gas transportation regulations, including how its regulations operate in conjunction with state proposals for natural gas marketing restructuring and in the increasingly competitive marketplace for all post-wellhead services related to natural gas. In recent years the FERC also has pursued a number of other important policy initiatives which could significantly affect the marketing of natural gas in the United States. Some of the more notable of these regulatory initiatives include: (1) a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate pipeline owned gathering facilities by interstate pipelines to their affiliates (the so-called "spin down" of previously regulated gathering facilities to the pipeline's nonregulated affiliates). (2) Order No. 497 involving the regulation of pipelines with marketing affiliates. (3) various FERC orders adopting rules proposed by the Gas Industry Standards Board which are designed to further standardize pipeline transportation tariffs and business practices. (4) a notice of proposed rulemaking that, among other things, proposes (a) to eliminate the cost-based price cap currently imposed on natural gas transactions of less than one year in duration, (b) to establish mandatory "transparent" capacity auctions of short-term capacity on a daily basis, and (c) to permit interstate pipelines to negotiate terms and conditions of service with individual customers. (5) issuance of Policy Statements regarding Alternate Rates and Negotiated Terms and Conditions of Service covering (a)the pricing of long-term pipeline transportation services by alternative rate mechanism options, including the pricing of interstate pipeline capacity utilizing market-based rates, incentive rates, or indexed rates, and (b) investigating of whether FERC should permit pipelines to negotiate the terms and conditions of service, in addition to rates of service. (6) a notice of proposed rulemaking that proposes generic procedures to expedite the FERC's handling of complaints against interstate pipelines with the goals of encouraging and supporting consensual resolutions of complaints and organizing the complaint procedures so that all complaints are handled in a timely and fair manner. Several of these initiatives are intended to enhance competition in natural gas markets, although some, such as "spin downs," may have the adverse effect of increasing the cost of doing business on some in the industry, including us, as a result of the geographic monopolization of those facilities by their new, unregulated owners. As to all of these FERC initiatives, the ongoing, or, in some instances, preliminary and evolving nature of these regulatory initiatives makes it impossible at this time to predict their ultimate impact on our 20 business. However, we do not believe that these FERC initiatives will affect us any differently than other natural gas producers and marketers with which we compete. Since Order 636, FERC decisions involving onshore facilities have been more liberal in their reliance upon traditional tests for determining what facilities are "gathering" and therefore exempt from federal regulatory control. In many instances, what was once classified as "transmission" may now be classified as "gathering." We ship certain of our natural gas through gathering facilities owned by others, including interstate pipelines, under existing long term contractual arrangements. Although these FERC decisions have created the potential for increasing the cost of shipping our natural gas on third party gathering facilities, our shipping activities have not been materially affected by these decisions. In summary, all of the FERC activities related to the transportation of natural gas have resulted in improved opportunities to market our physical production to a variety of buyers and market places, while at the same time increasing access to pipeline transportation and delivery services. Additional proposals and proceedings that might affect the natural gas industry in the United States are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The crude oil and natural gas industry historically has been very heavily regulated; thus there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. State and Other Regulation All of the jurisdictions in which we own producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions requiring permits for the drilling of wells and maintaining bonding requirements in order to drill or operate wells and provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units on an acreage basis and the density of wells which may be drilled and the unitization or pooling of crude oil and natural gas properties. In this regard, some states and provinces allow the forced pooling or integration of tracts to facilitate exploration while other states and provinces rely on voluntary pooling of lands and leases. In addition, state and provincial conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Some states, such as Texas and Oklahoma, have, in recent years, reviewed and substantially revised methods previously used to make monthly determinations of allowable rates of production from fields and individual wells. The effect of all of these conservation regulations is to limit the speed, timing and amounts of crude oil and natural gas we can produce from our wells, and to limit the number of wells or the location at which we can drill. State and provincial regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements, but does not generally entail rate regulation. In the United States, natural gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the State's more active review of rates, services and practices associated with the gathering and transportation of natural gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates. For those operations on U.S. Federal or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, in the United States, the Minerals Management Service ("MMS") has recently issued a final rule to clarify or severely limit the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS will not allow deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government. The crude oil and natural gas 21 industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations. Canadian Royalty Matters In addition to Canadian federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed preference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time the governments of Canada, Alberta and Saskatchewan have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging crude oil and natural gas exploration or enhanced planning projects. Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing crude oil reserves in Alberta. Crude oil produced from horizontal extensions commenced at least five years after the well was originally spudded may qualify for a royalty reduction. A 24-month, 8,000 cubic metres exemption is available to production from a well that has not produced for a 12-month period, if resuming production after January 31, 1993. In addition, crude oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992, is entitled to a 12-month royalty exemption (to a maximum of CDN $1 million). Crude oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects is also subject to royalty reductions. The Alberta government also introduced the Third Tier Royalty with a base rate of 10% and a rate cap of 25% from crude oil pools discovered after September 30, 1992. The new crude oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30% and for old crude oil a base rate of 10% and a rate cap of 35%. Effective January 1, 1994, the calculation and payment of natural gas royalties became subject to a simplified process. The royalty reserved to the Crown, subject to various incentives, is between 15% or 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory gas wells spudded or deepened after July 1, 1985 and before June 1, 1988 continues to be eligible for a royalty exemption for a period of 12 months, or such later time that the value of the exempted royalty quantity equals a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well. In Alberta, a producer of crude oil or natural gas is entitled to credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program is based on a price-sensitive formula, and the ARTC rate currently varies between 75% for prices for crude oil at or below CDN $100 per cubic metre and 35% for prices above CDN $210 per cubic metre. The ARTC rate is currently applied to a maximum of CDN $2.0 million of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on average "par price", as determined by the Alberta Department of Energy for the previous quarterly period. On December 22, 1997, the Government of Alberta gave notice that they intended to review the ARTC program, but no amendments have yet been passed into law. The government of Alberta did pass a law that effective January 1, 2001, the ARTC would not be available to individuals or trusts and will not otherwise be available unless the maximum credit is greater than or equal to CDN $10,000 in the taxation year. Producers of crude oil and natural gas in British Columbia are also required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of crude oil and natural gas produced from Crown and freehold lands respectively. The amount payable as a royalty in 22 respect of crude oil depends on the vintage of the crude oil (whether it was produced from a pool discovered before or after October 31, 1975) or a pool in which no well was completed on June 1, 1998), the quantity of crude oil produced in a month and the value of the crude oil. Crude oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. The royalty payable on natural gas is determined by a sliding scale based on a reference price which is the greater of the amount obtained by the producer and at prescribed minimum price. Natural gas produced in association with crude oil has a minimum royalty of 8% while the royalty in respect of other natural gas may not be less than 15%. Environmental Matters Our operations are subject to numerous federal, state, provincial and local laws and regulations controlling the generation, use, storage, and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as use of pits and plugging of abandoned wells; restrict injection of liquids into subsurface strata that may contaminate groundwater; and impose substantial liabilities for pollution resulting from our operations. Environmental permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on us as well as the crude oil and natural gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations. In the United States, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and comparable state statutes impose strict, joint, and several liability on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is common for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial civil and criminal penalties for failing to prevent surface and subsurface pollution, as well as to control the generation, transportation, treatment, storage and disposal of hazardous waste generated by crude oil and natural gas operations. Although CERCLA currently contains a "petroleum exclusion" from the definition of "hazardous substance," state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including crude oil cleanups. In addition, although RCRA regulations currently classify certain oilfield wastes which are uniquely associated with field operations as "non-hazardous," such exploration, development and production wastes could be reclassified by regulation as hazardous wastes thereby administratively making such wastes subject to more stringent handling and disposal requirements. We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Our operations are also impacted by regulations governing the disposal of naturally occurring radioactive materials ("NORM"). We must comply with the Clean Air Act and comparable state statutes which prohibit the emissions of air contaminants, although a majority of our 23 activities are exempted under a standard exemption. Moreover, owners, lessees and operators of crude oil and natural gas properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are usually causes of action based on negligence, trespass, nuisance, strict liability and fraud. United States federal regulations also require certain owners and operators of facilities that store or otherwise handle crude oil, such as us, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of crude oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to crude oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil. Our Canadian operations are also subject to environmental regulation pursuant to local, provincial and federal legislation which generally require operations to be conducted in a safe and environmentally responsible manner. Canadian environmental legislation provides for restrictions and prohibitions relating to the discharge of air, soil and water pollutants and other substances produced in association with certain crude oil and natural gas industry operations, and environmental protection requirements, including certain conditions of approval and laws relating to storage, handling, transportation and disposal of materials or substances which may have an adverse effect on the environment. Environmental legislation can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders. Certain federal environmental laws that may affect us include the Canadian Environmental Assessment Act which ensures that the environmental effects of projects receive careful consideration prior to licenses or permits being issued, to ensure that projects that are to be carried out in Canada or on federal lands do not cause significant adverse environmental effects outside the jurisdictions in which they are carried out, and to ensure that there is an opportunity for public participation in the environmental assessment process; the Canadian Environmental Protection Act ("CEPA") which is the most comprehensive federal environmental statute in Canada, and which controls toxic substances (broadly defined), includes standards relating to the discharge of air, soil and water pollutants, provides for broad enforcement powers and remedies and imposes significant penalties for violations; the National Energy Board Act which can impose certain environmental protection conditions on approvals issued under the Act; the Fisheries Act which prohibits the depositing of a deleterious substance of any type in water frequented by fish or in any place under any condition where such deleterious substance may enter any such water and provides for significant penalties; the Navigable Waters Protection Act which requires any work which is built in, on, over, under, through or across any navigable water to be approved by the Minister of Transportation, and which attracts severe penalties and remedies for non-compliance, including removal of the work. In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993. In addition to consolidating a variety of environmental statutes, the AEPEA also imposes certain new environmental responsibilities on crude oil and natural gas operators in Alberta. The AEPEA sets out environmental standards and compliance for releases, clean-up and reporting. The Act provides for a broad range of liabilities, enforcement actions and penalties. We are not currently involved in any administrative, judicial or legal proceedings arising under domestic or foreign federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our financial position or results of operations. Moreover, we maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area. We have a Corporate Environmental Policy and a detailed Environmental Management System in place to ensure continued compliance with environmental, health and safety laws and regulations. We believe that we have obtained and are in compliance with all material environmental permits, authorizations and approvals. 24 Title to Properties As is customary in the crude oil and natural gas industry, we make only a cursory review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before drilling commences, we require a thorough title search to be conducted, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The crude oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties. Employees As of March 22, 2002, we had 47 full-time employees in the United States, including 3 executive officers, 3 non-executive officers, 1 petroleum engineer, 1 geologist, 5 managers, 1 landman, 12 secretarial and clerical personnel and 21 field personnel. Additionally, we retain contract pumpers on a month-to-month basis. We retain independent geological and engineering consultants from time to time on a limited basis and expect to continue to do so in the future. As of March 22, 2002, Grey Wolf in Canada had 42 full-time employees, including 3 executive officers, 2 non-executive officers, 3 petroleum engineers, 3 geologists, 1 geophysicist, 18 technical and clerical personnel and 12 field personnel. Grey Wolf manages the operations of Canadian Abraxas pursuant to a management agreement between Canadian Abraxas and Grey Wolf. Under the management agreement, Canadian Abraxas reimburses Grey Wolf for reasonable costs or expenses attributable to Canadian Abraxas and for administrative expenses based upon the percentage that Canadian Abraxas' gross revenue bears to the total gross revenue of Canadian Abraxas and Grey Wolf. In 2001, Canadian Abraxas paid approximately $1.7 million to Grey Wolf pursuant to this management agreement. Item 2. Properties Primary Operating Areas Texas Our U.S. operations are concentrated in South and West Texas with over 99% of the PV-10 of our U.S. crude oil and natural gas properties at December 31, 2001, located in those two regions. We operate 91% of our wells in Texas. Operations in South Texas are concentrated along the Edwards trend in Live Oak and Dewitt Counties and in the Frio/Vicksburg trend in San Patricio County. We own an average 78% working interest in 57 wells with average daily production of 444 net Bbls of crude oil and NGLs and 14,057 net Mcf of natural gas per day for the year ended December 31, 2001. As of December 31, 2001 we had estimated net proved reserves in South Texas of 46,521 Mmcfe (78% natural gas) with a PV-10 of $35.6 million, 80% of which was attributable to proved developed reserves. Our West Texas operations are concentrated along the deep Devonian/Ellenberger formations and shallow Cherry Canyon sandstones in Ward County, the Spraberry trend in Midland County and in the Sharon Ridge Clearfork Field in Scurry County. We own an average 76% working interest in 154 wells with average daily production of 621 net Bbls of crude oil and NGLs and 7,351 net Mcf of natural gas per day for the year ended December 31, 2001. As of December 31, 2001, we had estimated net proved reserves in West Texas of 88,039 Mmcfe (82% natural gas) with a PV 10 of $41.6 million, 47% of which was attributable to proved developed reserves. During 2001, we drilled a total of 4 new wells (4 net) in Texas with a 100% success rate. Western Canada We own producing properties in western Canada, consisting primarily of natural gas reserves and interests ranging from 10% to 100% in approximately 200 miles of natural gas gathering systems and 12 natural gas processing plants. As 25 of December 31, 2001, Canadian Abraxas and Grey Wolf had estimated net proved reserves of 94,664 Mmcfe (85% natural gas) with a PV-10 of $132.5 million, 93% of which was attributable to proved developed reserves. For the year ended December 31, 2001, the Canadian properties produced an average of approximately 866 net Bbls of crude oil and NGLs per day and 26,500 net Mcf of natural gas per day. The natural gas processing plants had aggregate capacity of approximately 211 MMcf of natural gas per day (107 net MMcf). During 2001, we drilled a total of 12 new wells (9.3 net) in Canada with a 92% success rate. Exploratory and Developmental Acreage Our principal crude oil and natural gas properties consist of non-producing and producing crude oil and natural gas leases, including reserves of crude oil and natural gas in place. The following table indicates our interest in developed and undeveloped acreage as of December 31, 2001:
Developed and Undeveloped Acreage ----------------------------------------------------------------------- As of December 31, 2001 ----------------------------------------------------------------------- Developed Acreage (1) Undeveloped Acreage (2) --------------------------------- ----------------------------------- Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4) --------------- --------------- --------------- ------------------ Canada 79,380 51,456 755,623 494,138 Texas 27,479 20,444 11,876 11,520 Wyoming 3,200 3,200 59,591 55,758 --------------- --------------- --------------- ------------------ Total 110,059 75,100 827,090 561,416 =============== =============== =============== ==================
- --------------- (1) Developed acreage consists of acres spaced or assignable to productive wells. (2) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether or not such acreage contains proved reserves. (3) Gross acres refers to the number of acres in which we own a working interest. (4) Net acres represents the number of acres attributable to an owner's proportionate working interest and/or royalty interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres). Productive Wells The following table sets forth our total gross and net productive wells, expressed separately for crude oil and natural gas, as of December 31, 2001:
Productive Wells (1) --------------------------------------------------------------------- As of December 31, 2001 --------------------------------------------------------------------- State/Country Crude Oil Natural Gas ----------------- -------------------------------- ---------------------------------- Gross(2) Net(3) Gross(2) Net(3) - - - - --------------- -------------- --------------- ---------------- Canada 276.0 9.1 205.0 110.5 Texas 142.0 111.9 69.0 49.9 Wyoming 5.0 5.0 - - --------------- -------------- --------------- ---------------- Total 423.0 126.0 274.0 160.4 =============== ============== =============== ================
- ------------ (1) Productive wells are producing wells and wells capable of production. (2) A gross well is a well in which we own an interest. The number of gross wells is the total number of wells in which we own an interest. (3) A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of our fractional working interest owned in gross wells. Substantially all of our existing crude oil and natural gas properties, except for Grey Wolf's, are pledged to secure our indebtedness under the First Lien Notes and Second Lien Notes and substantially all of Grey Wolf's existing crude oil and natural gas properties are pledged to secure its indebtedness 26 under the Grey Wolf Facility. You should read the discussion under the heading "Management's Discussion of Financial Condition and Results of Operations--Liquidity and Capital Resources" for more information regarding our indebtedness. Reserves Information The crude oil and natural gas reserves of Abraxas have been estimated as of January 1, 2002, January 1, 2001, and January 1, 2000, by DeGolyer and MacNaughton, of Dallas, Texas. The reserves of Canadian Abraxas and Grey Wolf as of January 1, 2002, January 1, 2001 and January 1, 2000 have been estimated by McDaniel and Associates Consultants Ltd. of Calgary, Alberta. Crude oil and natural gas reserves, and the estimates of the present value of future net revenues therefrom, were determined based on then current prices and costs. Reserve calculations involve the estimate of future net recoverable reserves of crude oil and natural gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. The following table sets forth certain information regarding estimates of our crude oil, natural gas liquids and natural gas reserves as of January 1, 2002, January 1, 2001 and January 1, 2000: Estimated Proved Reserves --------------------------------- Proved Proved Total Developed Undeveloped Proved ---------- ----------- --------- As of January 1, 2000(1) (2) (3)(4) Crude oil (MBbls) ................... 5,513 1,606 7,119 NGLs (MBbls) ........................ 4,961 562 5,523 Natural gas (MMcf) .................. 154,221 35,894 190,115 As of January 1, 2001(1) (2) (3) Crude oil (MBbls) ................... 3,866 1,407 5,273 NGLs (MBbls) ........................ 3,135 436 3,571 Natural gas (MMcf) .................. 119,737 71,590 191,327 As of January 1, 2002 Crude oil (MBbls) ................... 1,980 1,170 3,150 NGLs (MBbls) ........................ 3,067 585 3,652 Natural gas (MMcf) .................. 111,243 77,514 188,757 - ------------------ (1) Includes 33,000 and 40,000 barrels of crude oil reserves owned by Grey Wolf of which 16,900 and 20,525 barrels are applicable to the minority interests' share of these reserves as of January 1, 2000 and 2001, respectively. (2) Includes 236,000 and 692,000 barrels of natural gas liquids reserves owned by Grey Wolf of which 121,098 and 355,083 barrels are applicable to the minority interests' share of these reserves as of January 1, 2000 and 2001, respectively. (3) Includes 21,710 and 21,389 Mmcf of natural gas reserves owned by Grey Wolf of which 11,140 and 10,975 Mmcf are applicable to the minority interests' share of these reserves as of January 1, 2000 and 2001, respectively. (4) Includes 343,941 Bbls of crude oil reserves; 2,448.6 Mbbls of natural gas liquids reserves and 25,810 Mmcf of natural gas reserves, attributable to the Wyoming properties which were sold in March 2000. These reserves were estimated internally. 27 The process of estimating crude oil and natural gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise. Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control. You should not assume that the present value of future net revenues referred to in this annual statement is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year of the estimate, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the Company's financial statements. As of December 31, 2001, the Company's net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, crude oil and natural gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved crude oil and natural gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural gas. The Company also used the subsequent prices to evaluate its Canadian properties, and reduced the 2001 year-end write-down to an amount of $2.6 million on those properties. Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor. The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the PV-10 thereof for the crude oil and natural gas properties described in this report are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 2001. The average sales prices as of such date used for purposes of such estimates were $18.26 per Bbl of crude oil, $16.29 per Bbl of NGLs and $2.20 per Mcf of natural gas. It is also assumed that we will make future capital expenditures of approximately $56.6 million in the aggregate, which are necessary to develop and realize the value of proved undeveloped reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein. We file reports of our estimated crude oil and natural gas reserves with the Department of Energy and the Bureau of the Census. The reserves reported to these agencies are required to be reported on a gross operated basis and therefore are not comparable to the reserve data reported herein. Crude Oil, Natural Gas Liquids, and Natural Gas Production and Sales Prices The following table presents our net crude oil, net natural gas liquids and net natural gas production, the average sales price per Bbl of crude oil and natural gas liquids and per Mcf of natural gas produced and the average cost of production per BOE of production sold, for the three years ended December 31, 2001: 28 2001 2000 1999 ----------- ------------- ------------- Crude oil production (Bbls) ....... 454,063 636,734 777,855 Natural gas production (Mcf) ...... 17,495,598 19,962,470 25,697,899 Natural gas liquids production (Bbls) ....................... 277,969 314,897 376,474 Mmcfe ............................. 21,888 25,672 32,623 Average sales price per Bbl of crude oil ....................$ 24.63 $ 18.69 $ 14.57 Average sales price per MCF of natural gas (1) ..............$ 3.20 $ 2.71 $ 1.66 Average sales price per Bbl of natural gas liquids ..........$ 21.51 $ 22.42 $ 13.40 Average sales price per Mcfe (1)...$ 3.35 $ 2.84 $ 1.81 Average cost of production per BOE produced (2) .............$ 5.10 $ 4.39 $ 3.30 (1) Average sales prices are net of hedging activity. (2) Crude oil and natural gas were combined by converting natural gas to a barrel oil equivalent ("BOE") on the basis of 6 Mcf natural gas =1 Bbl of crude oil. Production costs include direct operating costs, ad valorem taxes and gross production taxes. Drilling Activities The following table sets forth our gross and net working interests in exploratory, development, and service wells drilled during the three years ended December 31:
2001 2000 1999 ----------------------------- ---------------------------- -------------------------- Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) ------------ ---------- ------------ --------- ----------- -------- Exploratory(3) Productive(4) Crude oil - - - - 2.0 2.0 Natural gas 2.0 1.0 3.0 2.5 8.0 5.3 Dry holes(5) 1.0 .5 9.0 5.6 11.0 6.2 ------------ ---------- ------------ --------- ----------- -------- Total 3.0 1.5 12.0 8.1 21.0 13.5 ============ ========== ============ ========= =========== ======== Development(6) Productive (4) Crude oil 2.0 2.0 9.0 9.0 8.0 1.6 Natural gas 13.0 11.0 16.0 12.2 20.0 13.1 Dry holes (5) - - 3.0 3.0 9.0 4.5 ------------ ---------- ------------ --------- ----------- -------- 15.0 13.0 28.0 24.2 37.0 19.2 ============ ========== ============ ========= =========== ========
(1) A gross well is a well in which we own an interest. 29 (2) The number of net wells represents the total percentage of working interests held in all wells (e.g., total working interest of 50% is equivalent to 0.5 net well. A total working interest of 100% is equivalent to 1.0 net well). (3) An exploratory well is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir. (4) A productive well is an exploratory or a development well that is not a dry hole. (5) A dry hole is an exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. (6) A development well is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves. As of March 22, 2002, we had 5 wells in process of drilling, 2 in the U.S. and 3 in Canada. Since late 2001, Grey Wolf has drilled four wells of a six well program in the Lady Fern area of Northeast British Columbia. Two of the wells in which we own a 16.66% interest in each well have indicated some success and are being completed and production tested. Two wells were dry holes. The final two wells of the program are currently drilling. Office Facilities Our executive and administrative offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232. We also have an office in Midland, Texas. These offices, consisting of approximately 12,650 square feet in San Antonio and 570 square feet in Midland, are leased until March 2006 at an aggregate base rate of $19,500 per month. Grey Wolf leases 17,522 square feet of office space in Calgary, Alberta pursuant to a lease, which expires on April 30, 2003. Other Properties We own 10 acres of land, an office building, workshop, warehouse and house in Sinton, Texas, 160 acres of land in Coke County, Texas and a 50% interest in approximately two acres of land in Bexar County, Texas. All three properties are used for the storage of tubulars and production equipment. We also own 19 vehicles which are used in the field by employees. We own 2 workover rigs, which are used for servicing our wells as well as third party wells. Item 3. Legal Proceedings In 2001, the Company and the Partnership were named as defendants 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 has 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 estimated share of 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 30 the action is handled through a joint group of crude 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 December 31, 2001, 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. Item 4. Submission of Matters to a Vote of Security Holders No matter was submitted to a vote of our security holders during the fourth quarter of the fiscal year ended December 31, 2001. Item 4a. Executive Officers of Abraxas Certain information is set forth below concerning our executive officers, each of whom has been selected to serve until the 2002 annual meeting of shareholders and until his successor is duly elected and qualified. Robert L. G. Watson, age 51, has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. Since May 1996, Mr. Watson has also served as Chairman of the Board and a director of Grey Wolf. In November 1996, Mr. Watson was elected Chairman of the Board, President and as a director of Canadian Abraxas. Prior to joining Abraxas, Mr. Watson was employed in various petroleum engineering positions with Tesoro Petroleum Corporation, a crude oil and natural gas exploration and production company, from 1972 through 1977, and DeGolyer and McNaughton, an independent petroleum engineering firm, from 1970 to 1972. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974. Chris E. Williford, age 50, was elected Vice President, Treasurer and Chief Financial Officer of Abraxas in January 1993, and as Executive Vice President and a director of Abraxas in May 1993. In November 1996, Mr. Williford was elected Vice President and Assistant Secretary of Canadian Abraxas. In December 1999, Mr. Williford resigned as a director of Abraxas. Prior to joining Abraxas, Mr. Williford was Chief Financial Officer of American Natural Energy Corporation, a crude oil and natural gas exploration and production company, from July 1989 to December 1992 and President of Clark Resources Corp., a crude oil and natural gas exploration and production company, from January 1987 to May 1989. Mr. Williford received a Bachelor of Science degree in Business Administration from Pittsburgh State University in 1973. Robert W. Carington, Jr., age 40, was elected Executive Vice President and a director of the Company in July 1998. In December 1999, Mr. Carington resigned as a director of Abraxas. Prior to joining the Company, Mr. Carington was a Managing Director with Jefferies & Company, Inc. Prior to joining Jefferies & Company, Inc. in January 1993, Mr. Carington was a Vice President at Howard, Weil, Labouisse, Friedrichs, Inc. Prior to joining Howard, Weil, Labouisse, Friedrichs, Inc., Mr. Carington was a petroleum engineer with Unocal Corporation from 1983 to 1990. Mr. Carington received a degree of Bachelor of Science in Mechanical Engineering from Rice University in 1983 and a Masters of Business Administration from the University of Houston in 1990. 31 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters Market Information Our common stock began trading on the American Stock Exchange on August 18, 2000, under the symbol "ABP." Our common stock was formerly listed on the NASDAQ Stock Market under the symbol "AXAS"; however, effective June 16, 1999, our common stock was delisted from general quotation on the NASDAQ Stock Market for failure to satisfy NASDAQ's listing and maintenance standards. During the period between June 16, 1999 and August 17, 2000, our stock traded on the OTC Bulletin Board under the symbol "AXAS". The following table sets forth certain information as to the high and low bid quotations quoted on NASDAQ for 1999 (through June 16, 1999), on the OTC Bulletin Board for the remainder of 1999 and through August 17, 2000, and the high low sales price on the American Stock Exchange for the remainder of 2000 and 2001. Information with respect to over-the-counter bid quotations represents prices between dealers, does not include retail mark-ups, mark-downs, or commissions, and may not necessarily represent actual transactions.
Period High Low 1999 First Quarter......................................$3.19 $1.19 Second Quarter......................................2.82 0.88 Third Quarter...................................... 2.97 0.88 Fourth Quarter..................................... 2.44 0.81 2000 First Quarter......................................$2.81 $1.06 Second Quarter..................................... 2.38 1.34 Third Quarter (OTC through August 17).............. 2.75 1.38 Third Quarter (AMEX from August 17)................ 4.00 2.75 Fourth Quarter.................................... 4.56 2.81 2001 First Quarter......................................$5.32 $3.69 Second Quarter......................................4.98 3.10 Third Quarter.......................................3.65 1.70 Fourth Quarter......................................1.85 0.88
Holders As of March 22, 2002 we had 29,979,397 shares of common stock outstanding and had approximately 1,579 stockholders of record. Dividends We have not paid any cash dividends on our common stock and it is not presently determinable when, if ever, we will pay cash dividends in the future. In addition, the indentures governing the First Lien and Second Lien Notes prohibit the payment of cash dividends and stock dividends on our common stock. You should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for more information regarding the restrictions on our ability to pay dividends. 32 Item 6. Selected Financial Data The following selected financial data are derived from our Consolidated Financial Statements. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto, and other financial information included herein. See "Financial Statements."
Year Ended December 31, -------------------------------------------------------------------------------- 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- (Dollars in thousands except per share data) Total revenue.................................. $ 77,243 $ 76,600 $ 66,770 $ 60,084 $ 70,931 Income (loss) before extraordinary item........ $ (19,718)(1) $ 6,676 (2) $ (36,680)(3) $ (83,960) (3) $ (6,485) Income (loss) before extraordinary item per common share - diluted.................... $ (0.76) $ 0.21 $ (5.41) $ (13.26) $ (1.11) Weighted average shares outstanding - basic (in thousands)................................. 25,789 22,616 6,784 6,331 6,025 Total assets................................... $ 303,713 $ 335,560 $ 322,284 $ 291,498 $ 338,528 Long-term debt, excluding current maturities... $ 285,184 $ 266,441 $ 273,421 $ 299,698 $ 248,617 Total stockholders' equity (deficit)........... $ (28,488) $ (6,503) $ (9,505) $ (63,522) $ 26,813
(1) Includes ceiling test write-down of $2.6 million in 2001, based on subsequent (March 22, 2002) realized prices, relating to our Canadian properties. (2) Includes gain on sale of partnership interest of $34 million in 2000. (3) Includes ceiling write-down of $19.1 and $61.2 million for 1999 and 1998 respectively. Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations The following is a discussion of our consolidated 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. See "Financial Statements." General We have incurred net losses in three of the last four years and there can be no assurance that operating income and net earnings will be achieved in future periods. Our revenues, profitability and future rate of growth are substantially dependent upon prevailing prices for crude oil and natural gas and the volumes of crude oil, natural gas and natural gas liquids we produce. Natural gas and crude oil prices weakened during 1998. Crude oil and natural gas prices increased somewhat in 1999 and increased substantially in 2000. During 2001 crude oil and natural gas prices weakened substantially from the 2000 levels. 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. 33 Price volatility in the natural gas market has remained prevalent in the last few years. In the first quarter of 1999, we experienced a decline in energy commodity prices, resulting in lower revenues and net losses during this period. However, in the summer of 1999 and continuing through 2000 and early in 2001, prices improved. For the months of January 2001 through July 2001, we had certain crude oil and natural gas hedges in place that prevented us from realizing the full impact of this 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, prices again became depressed, primarily due to the economic downturn. The table below illustrates how natural gas prices fluctuated over the course of 2001. "Index" represents the last three days average of NYMEX traded contracts index price. The "2001" 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 ----------- ---------- ---------------- ---------------- Index $ 7.27 $ 4.82 $ 2.98 $ 2.47 2001 4.85 3.41 2.26 2.09 Prices have improved since December 31, 2001. The NYMEX natural gas price on March 22, 2002 was $3.43 per Mcf. Prices for crude oil have followed a similar path as the commodity market fell throughout 2001. The table below contains the last three days average of NYMEX traded contracts index price ("Index") and the prices realized by the Company during the quarter for 2001. (in $ per Bbl) Crude oil Prices by Quarter - -------------------------------------------------------------------------------- Quarter ended --------------------------------------------------------- March 31 June 30 September 30 December 31 ----------- ----------- ---------------- ---------------- Index $ 29.86 $ 27.94 $ 26.50 $ 22.12 2001 27.22 25.32 25.06 18.72 Prices have improved since December 31, 2001. The NYMEX crude oil price on March 22, 2002 was $25.35 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. In November 1996, we assumed hedge agreements extending through October 2001 with a counterparty involving various quantities and fixed prices. These hedge agreements provided that we 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 counterparty to make payments to us to the extent the market prices were less than such fixed prices. We accounted for the related gains or losses in crude oil and natural gas revenue in the period of the hedged production. We terminated these hedge agreements in January 1999 and were paid $750,000 by the counterparty for such termination. This amount is included in other income in the accompanying financial statements. In March 1998, we 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 34 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, we were paid when the average monthly price for crude oil on the NYMEX is below the floor price and paid the counterparty when the average monthly price exceeded the ceiling price. During the year ended December 31, 1999, we realized a loss of $1.8 million on this agreement, which is accounted for in crude oil and natural gas revenue. We also entered into a hedge agreement with Barrett Resources Corporation ("Barrett") for the period November 1999 through October 2000. This agreement was for 1,000 Bbls per day with us being paid $20.30 and an additional 1,000 barrels per day with a floor price of $18.00 per barrel and a ceiling of $22.00 per Bbl. We realized losses from hedges of $ 20.2 million and $12.1 million for the years ended December 31, 2000 and 2001 respectively, which is accounted for in crude oil and natural gas revenue. At year end 2001, 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 December 31, 2001, the fair market value of the remaining fixed price hedge agreement was a liability of approximately $658,000 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:
Years Ended December 31, -------------------------------------------------------------- (dollars in thousands, except per unit data) 2001 2000 1999 ------------------ ------------------ ------------------ Operating revenue:* Crude oil sales* $ 11,184 $ 11,899 $ 11,330 NGLs sales 5,979 7,061 5,043 Natural gas sales* 56,038 54,013 42,652 Gas processing revenue 2,438 2,717 4,244 Other 1,604 910 3,501 ------------------ ------------------ ------------------ Total operating revenue* $ 77,243 $ 76,600 $ 66,770 ================== ================== ================== Operating income (loss) $ 19,125 $ 11,943 $ (10,972) Crude oil production (MBbls) 454.1 636.7 777.9 NGLs production (MBbls) 278.0 314.9 376.5 Natural gas production (MMcf) 17,495.6 19,962.5 25,697.9 Average crude oil sales price (per Bbl)* $ 24.63 $ 18.69 $ 14.57 Average NGLs sales price (per Bbl)* $ 21.5 $ 22.42 $ 13.40 Average natural gas sales price (per Mcf)* $ 3.20 $ 2.71 $ 1.66
*Revenue and average sales prices are net of hedging activities. Comparison of Year Ended December 31, 2001 to Year Ended December 31, 2000 Operating Revenue. During the year ended December 31, 2001, operating revenue from crude oil, natural gas and natural gas liquids sales increased by $200,000 from $73.0 million in 2000 to $73.2 million in 2001. This increase was primarily attributable to an increase in commodity prices offset by a decline in production volumes. Increased prices contributed $12.9 million in additional revenue, which was offset by $12.7 million due to a decrease in production volumes. The decline in production was due to the disposition of certain properties, primarily in Canada, natural field declines and our inability to replace the production represented by the properties we have sold with new production from the producing properties we invested in with the proceeds of our property sales. 35 Natural gas liquids volumes declined from 314.9 MBbls in 2000 to 278.0 MBbls in 2001. Crude oil sales volumes declined from 636.7 MBbls in 2000 to 454.1 MBbls during 2001. Natural gas sales volumes decreased from 20.0 Bcf in 2000 to 17.5 Bcf in 2001. Production declines were primarily attributable to our disposition of assets during 2001 and our inability to replace the production represented by the properties we have sold with new production from the producing properties we invested in with the proceeds of our property sales. Average sales prices in 2001 net of hedging losses were: o $24.63 per Bbl of crude oil, o $21.51 per Bbl of natural gas liquids, and o $3.20 per Mcf of natural gas. Average sales prices in 2000 net of hedging losses were: o $18.69 per Bbl of crude oil, o $22.42 per Bbl of natural gas liquids, and o $2.71 per Mcf of natural gas. We also had natural gas processing revenue of $2.4 million in 2001 as compared to $2.7 million in 2000. The decline in processing revenue is due to a decrease in third party natural gas being processed. We are utilizing more of the plant capacity to process our own natural gas, leaving less capacity for third party processing. Lease Operating Expense. Lease operating expense ("LOE") and natural gas processing costs decreased slightly from $18.8 million in 2000 to $18.6 million in 2001. LOE on a per Mcfe basis for 2001 was $0.85 per Mcfe as compared to $0.73 per Mcfe in 2000. The increase in the per Mcfe cost is due to a decline in production volumes. G&A Expense. General and administrative ("G&A") expense decreased from $6.5 million in 2000 to $6.4 million in 2001. The decline in G&A expenses is primarily due to our efforts to control cost. Our G&A expense on a per Mcfe basis increased from $0.27 in 2000 to $0.29 in 2001. The increase in the per Mcfe cost was due primarily to lower production volumes in 2001 as compared to 2000. G&A - Stock-based Compensation Expense. 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 subject to variable accounting until they are exercised, forfeited, or expired. In March 1999, we amended the exercise price to $2.06 on all options with an existing exercise price greater than $2.06. We charged approximately $2.8 million to stock-based compensation expense in 2000 compared to crediting approximately $2.8 million in 2001. This was due to the decline in the market price of our Common stock during 2001. DD&A Expense. Depreciation, depletion and amortization ("DD&A") expense decreased by $3.4 million from $35.9 million in 2000 to $32.5 million in 2001. Our DD&A expense on a per Mcfe basis for 2001 was $1.48 per Mcfe as compared to $1.40 per Mcfe in 2000. The decline in DD&A is due to reductions in our full cost pool resulting from ceiling test write-downs in prior years, as well as lower production volumes. Interest Expense. Interest expense increased by $400,000 from $31.1 million to $31.5 million for 2001 compared to 2000. This increase resulted from an increase in debt levels during 2001 compared to 2000. The increase in our debt level was the result of additional sales pursuant to our production payment arrangement with Mirant Americas, as well as additional funding from the Grey Wolf Facility. Ceiling Limitation Write-down. We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting for crude 36 oil and natural gas properties. Under this method, the Company capitalizes the cost to acquire, explore for and develop crude oil and natural gas properties. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of crude oil and natural gas properties exceeds the ceiling limit, the Company is subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of the Company's stockholders' equity. The cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production, using commodity prices on the last day of the quarter, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the Company's financial statements. As of December 31, 2001, the Company's net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, crude oil and natural gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved crude oil and natural gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural gas. The Company also used the subsequent prices to evaluate its Canadian properties, and reduced the 2001 year-end write-down to an amount of $2.6 million on those properties. The risk that we will be required to write-down the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved resources are revised downward, a further write-down of the carrying value of our crude oil and natural gas properties may be required. See Note 18 of Notes to Consolidated Financial Statements. 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 through August 2001 increased to $1.7 million in 2001 from $1.3 million in 2000. This increase is due to improved profitability of Grey Wolf as a result of improved commodity prices received in 2001 as compared to 2000. As of December 31, 2001, 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 tax expense decreased from $3.7 million for the year ended December 31, 2000 to $2.4 million for the year ended December 31, 2001. The decrease was primarily due to the tax benefit relating to the ceiling limitation write-down relating to Canadian producing properties in 2001. Other. In March 2000, Abraxas Wamsutter L.P. ("Partnership") sold all of its interest in its crude oil and natural gas properties to a third party. Prior to the sale of these properties, effective January 1, 2000, the Company's equity investee share of crude oil and natural gas property cost, results of operations and amortization were not material to consolidated operations or financial position. As a result of the sale, the Company received approximately $34 million, which represented a proportional interest in the Partnership's proved properties. In June 2000, we retired $3.5 million of the Old Notes and $3.6 million of the Second Lien Notes at a discount of $1.8 million. 37 Comparison of Year Ended December 31, 2000 to Year Ended December 31, 1999 Operating Revenue. During the year ended December 31, 2000, operating revenue from crude oil, natural gas and natural gas liquids sales increased by $14.0 million from $59.0 million in 1999 to $73.0 million in 2000. This increase was primarily attributable to an increase in commodity prices. Increased prices contributed $26.5 million in additional revenue, which was offset by $12.5 million due to a decrease in production volumes. The decline in production was due to the disposition of certain properties, primarily in Canada. Natural gas liquids volumes declined from 376.5 MBbls in 1999 to 314.9 MBbls in 2000. Crude oil sales volumes declined from 777.9 MBbls in 1999 to 636.7 MBbls during 2000. Natural gas sales volumes decreased from 25.7 Bcf in 1999 to 20.0 Bcf in 2000. Production declines were primarily attributable to our disposition of assets during 2000. Average sales prices in 2000 net of hedging losses were: o $18.69 per Bbl of crude oil, o $22.42 per Bbl of natural gas liquids, and o $2.71 per Mcf of natural gas. Average sales prices in 1999 net of hedging losses were: o $14.57 per Bbl of crude oil, o $13.40 per Bbl of natural gas liquids, and o $1.66 per Mcf of natural gas. We also had natural gas processing revenue of $2.7 million in 2000 as compared to $4.2 million in 1999. The decline in processing revenue is due to a decrease in third party natural gas being processed. We are utilizing more of the plant capacity to process our own natural gas, leaving less capacity for third party processing. Lease Operating Expense. LOE and natural gas processing costs increased by $0.8 million from $17.9 million for 1999 to $18.8 million for 2000. LOE on a per Mcfe basis for 2000 was $0.73 per Mcfe as compared to $0.55 per Mcfe in 1999. The increase was due primarily to a general increase in the cost of services and increased production taxes due to higher commodity prices in 2000 as compared to 1999. The increase in the per Mcfe cost is due to a decline in production volumes. G&A Expense. G&A expense increased from $5.3 million for the year ended December 31, 1999 to $6.5 million for the year ended December 31, 2000. The increase in G&A was due to the loss of approximately $600,000 of overhead billed to the partnership, substantially all of the assets of which were sold in March 2000, and an increase in director compensation as a result of our restructuring in the fourth quarter of 1999. Our G&A expense on a per Mcfe basis increased from $0.16 in 1999 to $0.27 in 2000. The increase in the per Mcfe cost was due partly to lower production volumes in 2000 as compared to 1999 as well as the increase in expense in 2000 as compared to 1999. G&A - Stock-based Compensation Expense. 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 subject to variable accounting until they are exercised, forfeited, or expired. In March 1999, we amended the exercise price to $2.06 on all options with an existing exercise price greater than $2.06. We recognized approximately $2.8 million as stock-based compensation expense during 2000 related to these repricings. DD&A Expense. DD&A expense increased by $1.1 million from $34.8 million for the year ended December 31, 1999 to $35.9 million for the year ended December 31, 2000. Our DD&A expense on a per Mcfe basis for 1999 was $1.07 per Mcfe as compared to $1.40 per Mcfe in 2000. The increase in DD&A is the result of higher finding costs for 2000. 38 Interest Expense. Interest expense decreased by $5.7 million from $36.8 million to $31.1 million for the year ended December 31, 2000 compared to 1999. This decrease resulted from reduced debt levels during 2000 compared to 1999. The reduced debt level was the result of the exchange of approximately $269.7 million principal amount of our Old Notes for approximately $188.8 million principal of our Second Lien Notes, shares of our common stock and contingent value rights. Ceiling Limitation Write-down. We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting for crude oil and natural gas properties. Under this method, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties less related deferred taxes, is limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of crude oil and natural gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings, which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity. The risk that we will be required to write-down the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. For the year ended December 31, 1999, we recorded a write-down of $19.1 million, $11.9 million after tax, related to our Canadian properties. We cannot assure you that we will not experience additional write-downs in the future. Should commodity prices decline or if any of our proved reserves are revised downward , a further write-down of the carrying value of our crude oil and natural gas properties may be required. See Note 18 of Notes to Consolidated Financial Statements. Minority interest. Minority interest in the net income of Grey Wolf, our 49% owned subsidiary during 1999 and 2000, increased to $1.3 million in 2000 from $269,000 in 1999. This increase was due to improved profitability of Grey Wolf as a result of improved commodity prices received in 2000 as compared to 1999. Income taxes. Income tax expense (benefit) increased from a benefit of $12.6 million for the year ended December 31, 1999 to expense of $3.7 million for the year ended December 31, 2000. The benefit for the year ended December 31, 1999 was primarily attributable to the ceiling limitation write down that occurred in that year. Other. In March 2000, the Partnership sold all of its interest in its crude oil and natural gas properties to a third party. Prior to the sale of these properties, effective January 1, 2000, the Company's equity investee share of crude oil and natural gas property cost, results of operations and amortization were not material to consolidated operations or financial position. As a result of the sale, the Company received approximately $34 million, which represented a proportional interest in the Partnership's proved properties. In June 2000, we retired $3.5 million of the Old Notes and $3.6 million of the Second Lien Notes at a discount of $1.8 million. 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. 39 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 1999 and the last six months of 2001, 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 December 31, 2001; however, we cannot assure you that these prices can be sustained in the future. For more detailed descriptions of commodity prices, you should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations". As of December 31, 2001, the Company's net capitalized costs of crude oil and natural gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per Bbl for crude oil and $2.57 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, crude oil and natural gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved crude oil and natural gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for crude oil and $2.89 per Mcf for natural gas. The Company also used the subsequent prices to evaluate its Canadian properties, and reduced the 2001 year-end write-down to an amount of $2.6 million on those properties. 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. Working Capital. At December 31, 2001, we had current assets of $17.3 million and current liabilities of $22.3 million resulting in a working capital deficit of $5.0 million. The majority of our current liabilities at December 31, 2001, were trade accounts payable of $10.5 million, revenues due third parties of $3.6 million and accrued interest of $6.0 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 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 40 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. See Part I, Item 1, Business - "Recent Events". Capital Expenditures. Capital expenditures in 1999, 2000 and 2001 were $128.7 million, $74.4 million and $57.1 million, respectively. The table below sets forth the components of these capital expenditures on a historical basis for the three years ended December 31, 1999, 2000 and 2001. Year Ended December 31, ------------------------------- 2001 2000 1999 -------- --------- --------- (dollars in thousands) Expenditure category: Property acquisitions $ -- $ 7,189 $ 89,743 Development ......... 56,694 64,873 37,344 Facilities and other 362 2,350 1,621 -------- -------- -------- Total ............... $ 57,056 $ 74,412 $128,708 ======== ======== ======== During 2001 and 2000, expenditures were primarily for the development of existing properties. In 1999, expenditures were primarily the acquisition of New Cache Petroleums, Ltd. These expenditures were funded through internally generated cash flow, the issuance of $63.5 million of the First Lien Notes, borrowings under a credit facility and the sale of assets. As cash flow permits our current budget for capital expenditures for 2002 other than acquisition expenditures is $37.4 million, approximately $11.0 million of which has been spent as of March 15, 2002. 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:
2001 2000 1999 -------- --------- --------- (dollars in thousands) Net cash provided by operating activities ......... $ 16,300 $ 21,400 $ 3,900 Net cash provided by (used in) financing activities 20,700 (3,800) 49,100 Net cash provided by (used in) investing activities (30,800) (18,800) (111,200) --------- --------- --------- Total ............................................. $ 6,200 $ (1,200) $ (58,200) ========= ========= =========
Operating activities for the year ended December 31, 2001, provided us $16.3 million of cash. Investing activities used $30.8 million during 2001. Our investing activities included the sale of properties which provided $28.9 million, and the use of $57.1 million primarily for the development of producing properties. Financing activities provided $20.7 million during 2001, including the provision of additional funding of $11.7 million under our production payment arrangement with Mirant Americas, and the provision of $18.3 million under the Grey Wolf Facility. Payments on long term debt used $9.3 million. 41 Operating activities for the year ended December 31, 2000, provided us $21.4 million of cash. Investing activities used $18.8 million during 2000 comprised of $34.5 million provided from the sale of an equity investment in Wamsutter Holdings LP, $21.2 million provided from the sale of properties and $74.4 million used primarily for the acquisition and development of producing properties. Financing activities used $3.8 million during 2000. Operating activities for the year ended December 31, 1999, provided us $3.9 million of cash. Investing activities used $111.2 million during 1999, comprised of $17.5 million provided from the sale of crude oil and natural gas producing properties and $128.7 million used primarily for the acquisition and development of producing properties. Financing activities provided $49.1 million during 1999. 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. For more information regarding our liquidity needs, you should also read Business - "Recent Events". Future Capital Resources. We will have four principal sources of liquidity going forward: (i) cash on hand, (ii) cash flow from operations, (iii) the 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; 42 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. For more information regarding our liquidity needs, you should also read Business -"Recent Events". Although there may be questions regarding our viability as a going concern, management believes that the successful disposition of certain assets will allow us to meet our liquidity needs for the next year, including the repayment of the $63.5 million in principal amount of the First Lien Notes maturing in March 2003. 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 December 31, 2001.
Payments due in: ---------------------------------------------------------------------------- 2005 and Contractual Obligations Total 2002 2003 2004 after - --------------------------------------------------------------------------------------------------------------- Dollars in thousands - --------------------------------------------------------------------------------------------------------------- Long-Term Debt (1) (2) $285,599 $ - $63,500 $190,979 $ 22,944 (3) Operating Leases (4) 1,513 528 336 236 413
(1) Includes $63.5 million of the First Lien Notes, $191.0 million of the Old Notes and Second Lien Notes, $22.9 million under the Grey Wolf Facility and $8.2 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. 43 (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 December 31, 2001 ($23.0 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." (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 2002 for existing operations and leaseholds is approximately $37 million. Long-Term Indebtedness Old 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 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 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 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: 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 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 a wholly-owned Abraxas subsidiary, Sandia Oil & Gas Corporation. 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 these obligations. Upon a change of control, as defined in the Old Notes Indenture, each holder of the Old Notes will have the right to require Abraxas and Canadian Abraxas 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, Abraxas and Canadian Abraxas 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. 44 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. The First Lien Notes are redeemable, in whole or in part, at the option of Abraxas at 100% of the principal amount, plus accrued and unpaid interest to the date of redemption. The First Lien Notes are senior indebtedness of Abraxas secured by a first lien or charge 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 one of our wholly-owned subsidiaries, Wamsutter Holdings, Inc. (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 Canadian Abraxas. Upon a change of control, as defined in the First Lien Notes Indenture, each holder of the First Lien Notes will have the right to require Abraxas to repurchase such holder's First Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas will be obligated to offer to repurchase the First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales. The First Lien Notes indenture contains certain covenants that limit the ability of Abraxas and certain of its subsidiaries, including the guarantors of the First Lien Notes to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas. The First Lien Notes indenture provides, among other things, that Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas or any other Restricted Subsidiary except for such encumbrances or restrictions existing under or by reason of: (1) applicable law; (2) the First Lien Notes indenture; (3) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries; (4) any instrument governing indebtedness assumed by us in an acquisition, which encumbrance or restriction is not applicable to such Restricted Subsidiary or the properties or assets of such subsidiary other than the entity or the properties or assets of the entity so acquired; (5) agreements existing on the Issue Date (as defined in the First Lien Notes indenture) to the extent and in the manner such agreements were in effect on the Issue Date; (6) customary restrictions with respect to subsidiaries of Abraxas pursuant to an agreement that has been entered into for the sale or disposition of capital stock or assets of such Restricted Subsidiary to be consummated in accordance with the terms of the First Lien Notes indenture or any Security Documents (as defined in the First Lien Notes indenture) solely in respect of the assets or capital stock to be sold or disposed of; (7) any instrument governing certain liens permitted by the First Lien Notes indenture, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such lien; or 45 (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 completed an Exchange Offer whereby $269,699,000 of the Old Notes were exchanged for $188,778,000 of the new Second Lien Notes. 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 on or after December 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 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 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: 46 (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 (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. 47 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, 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. 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 48 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 $34,763,000 and $39,670,000 for deferred tax assets at December 31, 2000 and 2001, respectively. Critical Accounting Policies The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Crude oil and Natural gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. Abraxas has chosen to follow the full cost method. At the time it was adopted, management believed that this method would be preferable, as earnings tend to be less volatile than under the successful efforts method. See Note 1 of the Notes to Consolidated Financial Statements. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. The Company has experienced this situation several times over the years and experienced it again in 2001. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting. Under the full cost method of accounting, we record the carrying value of our crude oil and natural gas properties, and capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. The net capitalized cost of crude oil and natural gas properties less related deferred taxes, is limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of crude oil and natural gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders' equity. The risk that we will be required to write-down the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we have 49 substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. For the year ended December 31, 2001, we recorded a write-down of $2.6 million, related to our Canadian proved reserves. The write-down in 2001 was due to low commodity prices. For the year ended December 31, 1999, we recorded a write-down of $19.1 million, related to our Canadian properties. We cannot assure you that we will not experience additional write-downs in the future. Should commodity prices decline, a further write-down of the carrying value of our crude oil and natural gas properties may be required. See Note 18 of Notes to Consolidated Financial Statements. Hedge Accounting. Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities", was effective for the Company on January 1, 2001. SFAS 133, as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. All derivatives, whether designated in hedging relationships or not, will be required to be recorded on the balance sheet at fair value. If the derivative is designated a fair-value hedge, the changes in the fair value of the derivative and the hedged item will be recognized in earnings. If the derivative is designated a cash-flow hedge, changes in the fair value of the derivative will be recorded in other comprehensive income (OCI) and will be recognized in the income statement when the hedged item affects earnings. SFAS 133 defines new requirements for designation and documentation of hedging relationships as well as ongoing effectiveness assessments in order to use hedge accounting. For a derivative that does not qualify as a hedge, changes in fair value will we recognized in earnings. New Accounting Pronouncements In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations, which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. The Company has applied these standards to its purchase of the minority interest of Grey Wolf. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an asset retirement obligation to be recorded at fair value during the period incurred and an equal amount recorded as an increase in the value of the related long-lived asset. The capitalized cost is depreciated over the useful life of the asset and the obligation is accreted to its present value each period. SFAS No. 143 is effective for the Company beginning January 1, 2003 with earlier adoption encouraged. The Company is currently evaluating the impact the standard will have on its future results of operations and financial condition. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets. SFAS No. 144 retains the requirement to recognize an impairment loss only where the carrying value of a long-lived asset is not recoverable from its undiscounted cash flows and to measure such loss as the difference between the carrying amount and fair value of the asset. SFAS No. 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from the discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. SFAS No. 144 is effective for the Company beginning January 1, 2002 with earlier adoption encouraged. The Company is currently evaluating the impact the standard will have on its future results of operations and financial condition. Item 7A. Quantitative and Qualitative Disclosures about Market Risk Commodity Price Risk As an independent crude oil and natural gas producer, our revenue, cash flow from operations, other income and equity earnings and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of crude oil, natural gas and natural gas liquids. 50 Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of crude oil and natural gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global political and economic conditions. Historically, prices received for crude oil and natural gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. We attempt to manage the volatility of crude oil and natural gas prices through the periodic use of commodity price hedging agreements. We covered approximately 42% of our production in 2001 with hedge agreements. Without those arrangements, our realized natural gas prices would have been $0.70 per Mcf higher in 2001. You should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations " for more information regarding our hedging activities and impact of commodity price changes. Assuming the production levels we attained during the year ended December 31, 2001, a 10% decline in crude oil, natural gas and natural gas liquids prices would have reduced our operating revenue, cash flow and net income by approximately $7.3 million for the year. See Part I, Item 1, Business - "Recent Events". Hedging Sensitivity The fair value of our remaining hedge instrument was determined based on NYMEX forward price quotes as of December 31, 2001. As of December 31, 2001, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of our hedging instrument of $1.2 million and a commodity price decrease of 10% would have resulted in a favorable change in the fair value of our hedge instrument of $852,000. The following table sets forth our hedge position as of December 31, 2001.
Time Period Notional Quantities Price Fair Value - ------------------------------------------------ --------------------------- ---------------------------- -------------------- January 1, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $(658,000) gas or 1,000 Bbl/day of $2.60-$2.95 natural gas or crude oil $18.90 Crude oil
Interest rate risk At December 31, 2001, substantially all of Abraxas' long-term debt was at fixed interest rates from 11.5% to 12.875% and not subject to fluctuations in market rates and Grey Wolf's long-term debt was at a fixed interest rate of 9.5%. Foreign currency Our Canadian operations are measured in the local currency of Canada. As a result, our financial results are affected by changes in foreign currency exchange rates or weak economic conditions in the foreign markets. Canadian operations reported a pre-tax loss of $1.3 million for the year ended December 31, 2001. It is estimated that a 5% change in the value of the U.S. dollar to the Canadian dollar would have changed our net income by approximately $65,000. 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. Item 8. Financial Statements For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements . Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None 51 PART III Item 10. Directors and Executive Officers of the Registrant There is incorporated in this Item 10 by reference that portion of our definitive proxy statement for the 2002 Annual Meeting of Stockholders which appears therein under the caption "Election of Directors". See also the information in Item 4a of Part I of this Report. Item 11. Executive Compensation There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2002 Annual Meeting of Stockholders which appears therein under the caption "Executive Compensation", except for those parts under the captions "Compensation Committee Report on Executive Compensation," "Performance Graph", "Audit Committee Report" and "Report on Repricing of Options." Item 12. Security Ownership of Certain Beneficial Owners and Management There is incorporated in this Item 12 by reference that portion of our definitive proxy statement for the 2002 Annual Meeting of Stockholders which appears therein under the caption "Securities Holdings of Principal Stockholders, Directors and Officers." Item 13. Certain Relationships and Related Transactions There is incorporated in this Item 13 by reference that portion of our definitive proxy statement for the 2002 Annual Meeting of Stockholders which appears therein under the caption "Certain Transactions." PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a)1. Consolidated Financial Statements Page ---- Report of Deloitte & Touche LLP, Independent Auditors...............F-2 Report of Ernst & Young LLP, Independent Auditors...................F-3 Consolidated Balance Sheets, December 31, 2001 and 2000........................................F-4 Consolidated Statements of Operations, Years Ended December 31, 2001, 2000 and 1999......................F-6 Consolidated Statements of Stockholders' Equity (Deficit) Years Ended December 31, 2001, 2000 and 1999.....................F-7 Consolidated Statements of Cash Flows Years Ended December 31, 2001, 2000 and 1999......................F-9 Notes to Consolidated Financial Statements.........................F-11 Grey Wolf Exploration Inc. Report of Deloitte & Touche LLP, Independent Auditors..............F-43 Report of Ernst & Young LLP, Independent Auditors..................F-45 Balance Sheets at December 31, 2001 and 2000.......................F-46 Statements of Earnings and Retained Earnings Years ended December 31, 2001, 2000 and 1999.....................F-47 Statements of Cash Flows Years ended December 31, 2001, 2000 and 1999.....................F-48 Notes to Financial Statements......................................F-49 (a)2. Financial Statement Schedules 52 All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto. (a)3.Exhibits The following Exhibits have previously been filed by the Registrant or are included following the Index to Exhibits. Exhibit Number. Description 3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to Abraxas' Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration Statement")). 3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement). 3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement). 3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to Abraxas' Registration Statement on Form S-3, No. 333-00398 (the "S-3 Registration Statement")). 3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000 (Filed as Exhibit 3.5 to Abraxas' Annual Report of Form 10-K filed April 2, 2001) 3.6 Amended and Restated Bylaws of Abraxas. (Filed herewith). 4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement). 4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to Abraxas' Annual Report on Form 10-K filed on March 31, 1995). 4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1 to Abraxas' Registration Statement on Form 8-A filed on December 6, 1994). 4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between Abraxas and American Stock Transfer & Trust Company (Filed as Exhibit 1 to Amendment No. 1 to Abraxas' Registration Statement on Form 8-A filed on August 20, 1997). 4.5 Second Amendment to Rights Agreement as of May 22, 1998, by and between Abraxas and American Stock Transfer & Trust Company (Filed as Exhibit 1 to Amendment No. 2 to Abraxas' Registration Statement on Form 8-A filed on August 24, 1998) 4.6 Indenture dated January 27, 1999 by and among Abraxas, Canadian Abraxas and IBJ Schroder Bank & Trust Company (filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K dated February 5, 1999). 4.7 Third Supplemental Indenture dated December 21, 1999, by and among Abraxas, Canadian Abraxas and The Bank of New York f/k/a IBJ Schroder Bank & Trust Company (Filed as Exhibit 4.7 to Abraxas' Registration Statement on Form S-1, No. 333-95281 (the "2000 S-1 Registration Statement")). 53 4.8 Indenture dated March 26, 1999 by and among Abraxas, Canadian Abraxas, New Cache, Sandia and Norwest Bank Minnesota, National Association (Filed as Exhibit 4.6 to Abraxas' Annual Report on Form 10-K dated March 31, 1999). 4.9 Indenture dated December 21, 1999, by and among Abraxas, Canadian Abraxas, Sandia, New Cache, Wamsutter and Firstar Bank, National Association (Filed as Exhibit T3C to Abraxas' and Canadian Abraxas' Indenture Qualification on Form T3-A, No. 022-22449). 4.10 Form of Old Note (Filed as Exhibit A to Exhibit 4.6). 4.11 Form of First Lien Note (Filed as Exhibit A to Exhibit 4.8). 4.12 Form of Second Lien Note (Filed as Exhibit A to Exhibit 4.9). *10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as amended and restated. (Filed as Exhibit 10.7 to Abraxas' Annual Report on Form 10-K filed April 14, 1993). *10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as amended and restated. (Filed as Exhibit 10.8 to Abraxas' Annual Report on Form 10-K filed April 14, 1993). *10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan. (Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed April 14, 1993 *10.4 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to Abraxas and Canadian Abraxas' Registration Statement on Form S-4, No. 333-18673, (the "1996 Exchange Offer Registration Statement")). *10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as Exhibit 10.5 to the 1996 Exchange Offer Registration Statement). *10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors. (Filed as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994). *10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan. (Filed as Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994). *10.8 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994). 10.9 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to the 1993 S-1 Registration Statement). 10.10 Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.30 to the 1993 S-1 Registration Statement). *10.11 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the 2000 S-1 Registration Statement). *10.12 Employment Agreement between Abraxas and Chris E. Williford. (Filed as Exhibit 10.20 to the 2000 S-1 Registration Statement). *10.13 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the S-3 Registration Statement). 54 *10.14 Employment Agreement between Abraxas and Robert W. Carington, Jr. (Filed as Exhibit 10.22 to the 2000 S-1 registration Statement). 10.15 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and Basil Street Company (Filed as Exhibit 10.15 to Abraxas Annual Report on Form 10-K filed on April 2, 2001). 10.16 Common Stock Purchase Warrant dated September 1, 2000 between Jessup & Lamont Holdings (Filed as Exhibit 10.16 to Abraxas Annual Report on Form 10-K filed on April 2, 2001). 10.17 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and TNC, Inc. (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K filed on April 2, 2001). 10.18 Common Stock Purchase Warrant dated August 1, 2000 between Abraxas and Charles K. Butler (Filed as Exhibit 10.17 to Abraxas Annual Report on Form 10-K filed on April 2, 2001). 10.19 Management Agreement dated November 14, 1996 by and between Canadian Abraxas and Cascade Oil & Gas Ltd. (Filed as Exhibit 10.36 to the 1996 Exchange Offer Registration Statement). 10.20 Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of November 12, 1999 by and between Wamsutter Holdings, Inc. and TIFD III-X Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed November 30,1999). 10.21 Credit agreement dated December 20, 2001 between Grey Wolf Exploration, Inc. and Mirant Energy Capital, Ltd. (Filed herewith) 10.22 First Overriding Royalty Agreement dated as of December 20, 2001 between Grey Wolf Exploration, Inc. and Mirant Energy Capital, Ltd (Filed herewith) 10.23 Second Over Overriding Royalty Agreement dated as of December 20, 2001 between Grey Wolf Exploration, Inc. and Mirant Energy Capital, Ltd (Filed herewith) 10.24 Purchase Agreement for Dollar Denominated Production Payment dated as of October 6, 1999 by and between Abraxas and Southern Producer Services, L.P. (Filed as Exhibit 10.1 to Abraxas' Quarterly Report on Form 10-Q filed November 15, 1999) 10.25 Conveyance of Dollar Denominated Production Payment dated as of October 6, 1999 by and between Abraxas and Southern Producer Services, L.P. (Filed as Exhibit 10.2 to Abraxas' Quarterly Report on Form 10-Q filed November 15, 1999) 21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas' Annual Report on Form 10-K filed March 31, 2000). 23.1 Independent Auditors' Consent (Deloitte & Touche LLP). (Filed herewith). 23.2 Consent of Independent Auditors (Ernst & Young LLP). (Filed herewith). 23.3 Independent Auditors' Consent(Deloitte & Touche LLP Chartered Accountants). (Filed herewith). 23.4 Independent Auditors' Consent(Deloitte & Touche LLP Chartered Accountants). (Filed herewith). 23.5 Consent of DeGolyer and MacNaughton. (Filed herewith). 23.6 Consent of McDaniel & Associates Consultants, Ltd. (Filed herewith). * Management Compensatory Plan or Agreement. 55 (b) Reports on Form 8-K 1. Current Report on Form 8-K filed on October 3, 2001, Item 5. Other Events, including a press release relating to an update of operational activities and operational guidance for the third and fourth quarter. 2. Current Report on Form 8-K filed on October 9, 2001, Item 5. Other Events, including a press release announcing the completion of the Company's tender offer for the shares of Grey Wolf not owned by the Company. 3. Current Report on the Form 8-K filed on November 14, 2001, Item 5. Other Events, including a press release relating to the announcement of the Company's third quarter financial results and updating operations. 4. 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. 5. Current Report on the Form 8-K 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. 6. Current Report on the Form 8-K 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. 56 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ABRAXAS PETROLEUM CORPORATION By: /s/ Robert L.G. Watson By: /s/ Chris E. Williford ------------------------------------ ---------------------------- President and Principal Exec. Vice President and Executive Officer Principal Financial and Accounting Officer DATED:April 5, 2002 Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. Signature Name and Title Date /s/ Robert L.G. Watson Chairman of the Board, - ----------------------------- President (Principal Executive Robert L.G. Watson Officer) and Director 4/5/2002 /s/ Chris E. Williford Exec. Vice President and - ----------------------------- Treasurer (Principal Financial Chris Williford and Accounting Officer) 4/5/2002 /s/ Craig S. Bartlett, Jr. Director 4/5/2002 - ----------------------------- Craig S. Bartlett, Jr. /s/ Franklin Burke Director 4/5/2002 - ----------------------------- Franklin Burke /s/ Ralph F. Cox Director 4/5/2002 - ---------------------- Ralph F. Cox /s/ Fredrick M. Pevow, Jr. Director 4/5/2002 - ----------------------------- Fredrick M. Pevow, Jr. /s/ James C. Phelps Director 4/5/2002 - ----------------------------- James C. Phelps /s/ Joseph A. Wagda Director 4/5/2002 - ---------------------- Joseph A. Wagda 57 Exhibit 23.1 Independent Auditors' Consent We consent to the incorporation by reference in the Registration Statements No. 33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377 of Abraxas Petroleum Corporation on Form S-8 of our report dated March 26, 2002, appearing in this Annual Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December 31, 2001. /s/ Deloitte & Touche LLP San Antonio, Texas March 29, 2002 58 Exhibit 23.2 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in the Registration Statements (Form S-8 No. 33-48932) pertaining to the Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan; (Form S-8 No. 33-48934) pertaining to the Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan; (Form S-8 No. 33-72268) pertaining to the Abraxas Petroleum Corporation 1993 Key Contribution Stock Option Plan; (Form S-8 No. 33-81416) pertaining to the Abraxas Petroleum Corporation Restricted Share Plan for Directors; (Form S-8 No. 33-81418) pertaining to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan; (Form S-8 No. 333-17375) pertaining to the Abraxas Petroleum Corporation Director Stock Option Plan; and (Form S-8 No. 333-17377) pertaining to the Abraxas Petroleum Corporation 401(K) Profit Sharing Plan of our report dated March 17, 2000, with respect to the consolidated financial statements of Abraxas Petroleum Corporation included in the Annual Report (Form 10-K) for the year ended December 31, 2001. /s/ Ernst & Young LLP Ernst & Young LLP San Antonio, Texas April 3, 2002 59 Exhibit 23.3 Independent Auditors' Consent We consent to the incorporation by reference in the Registration Statements No. 33-48932, 33-48934, 33-72268, 33-81418, 333-17375 and 333-17377 of Abraxas Petroleum Corporation on Form S-8 of our report dated March 31, 2002 on the financial statements of Grey Wolf Exploration Inc. appearing in this Annual Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December 31, 2001. Calgary, Canada /s/Deloitte & Touche LLP April 3, 2002 Chartered Accountants 60 Exhibit 23.4 Consent of DeGolyer and MacNaughton We hereby consent to the incorporation in your Annual Report on Form 10-K of the references to DeGolyer and MacNaughton in the "Reserves Information" section and to the use by reference of information contained in our "Appraisal Report as of December 31, 2001 on Certain Interests owned by Abraxas Petroleum Corporation," Appraisal Report as of December 31,02000 on Certain Interest owned by Abraxas Petroleum Corporation," and "Appraisal Repost as of December 31, 1999, on Certain Interest owned by Abraxas Petroleum Corporation" (our Reports). However, that since the crude oil, condensate, natural gas liquids, and natural gas reserves estimates set forth in our Reports have been combined with reserve estimates of other petroleum consultants, we are necessarily unable to verify the accuracy of the reserves values contained in the aforementioned Annual Report. DeGolyer and MacNaughton Dallas, Texas April 3, 2002 61 Exhibit 23.5 Consent of McDaniel and Associates Consultants LTD. We consent to the incorporation in your Annual Report on Form 10-K of the references to McDaniel and Associates Consultants Ltd. in the "Reserves Information" section and to the use by reference of information contained in our Evaluation Report "Canadian Abraxas Petroleum Ltd., Evaluation of Oil & Gas Reserves, As of January 1, 2002", dated March 22, 2002. McDaniel & Associates Consultants LTD Calgary, Alberta April 3, 2002 62 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Abraxas Petroleum Corporation and Subsidiaries Independent Auditors' Reports for the years ended December 31, 2001 and 2000..............................................F-2 Independent Auditors' Report for the year ended December 31, 1999 ..........F-3 Consolidated Balance Sheets at December 31, 2000 and 2001 ..................F-4 Consolidated Statements of Operations for the years ended December 31, 1999, 2000 and 2001 .......................................F-6 Consolidated Statements of Stockholders' Equity (Deficit) for the years ended December 31, 1999, 2000 and 2001 ...................F-7 Consolidated Statements of Cash Flows for the years ended December 31, 1999, 2000 and 2001 .......................................F-9 Notes to Consolidated Financial Statements .................................F-11 Grey Wolf Exploration Inc. Auditors' Report for the years ended December 31, 2001 and 2000.............F-45 Comments by Auditors' for US readers on Canada - US reporting differences............................................................F-46 Auditors' Report for the year ended December 31, 1999.......................F-47 Balance Sheets at December 31, 2000 and 2001................................F-48 Statements of Earnings and Retained Earnings for the years ended December 31, 1999, 2000 and 2001.................................F-49 Statements of Cash Flows for the years ended December 31, 1999, 2000 and 2001.......................................F-50 Notes to Financial Statements...............................................F-51 F-1 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Abraxas Petroleum Corporation We have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation and Subsidiaries (the "Company") as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders' equity (deficit), and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2001 and 2000, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 16 to the financial statements, in 2001 the Company changed its method of accounting for derivative financial instruments to conform to Statement of Financial Accounting Standards No. 133. /s/DELOITTE & TOUCHE LLP San Antonio, Texas March 26, 2002 F-2 INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders Abraxas Petroleum Corporation We have audited the accompanying consolidated statement of operations of Abraxas Petroleum Corporation and Subsidiaries as of December 31, 1999, and the related consolidated statements of stockholders' equity (deficit) and cash flows for the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Abraxas Petroleeum Corporation and Subsidiaries for the year ended December 31, 1999, in conformity with accounting principles accepted in the United States. ERNST & YOUNG LLP San Antonio, Texas March 17, 2000, F-3
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS December 31 -------------------------------------- 2000 2001 ------------------ ------------------- (Dollars in thousands) Current assets: Cash ................................................... $ 2,004 $ 7,605 Accounts receivable, less allowance for doubtful accounts: Joint owners ....................................... 3,771 2,785 Oil and gas production sales ....................... 16,106 4,758 Other .............................................. 841 504 ------------------ ------------------- 20,718 8,047 Equipment inventory .................................... 1,411 1,251 Other current assets ................................... 179 443 ------------------ ------------------- Total current assets ................................. 24,312 17,346 Property and equipment: Oil and gas properties, full cost method of accounting: Proved ............................................. 481,802 486,098 Unproved, not subject to amortization .............. 12,831 10,626 Other property and equipment ......................... 63,720 67,632 ------------------ ------------------- Total .......................................... 558,353 564,356 Less accumulated depreciation, depletion, and amortization ..................................... 253,569 282,462 ------------------ ------------------- Total property and equipment - net ................. 304,784 281,894 Deferred financing fees, net of accumulated amortization of $6,917 and $8,668 at December 31, 2000 and 2001, respectively ........................................... 5,556 3,928 Other assets .............................................. 908 545 ------------------ ------------------- Total assets ........................................... $ 335,560 $ 303,713 ================== ===================
See accompanying Notes to Consolidated Financial Statements. F-4
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (CONTINUED) LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) December 31 -------------------------------------- 2000 2001 ------------------ ------------------- (Dollars in thousands) Current liabilities: Accounts payable .......................................... $ 22,721 $ 10,542 Joint interest oil and gas production payable ............. 6,281 3,596 Accrued interest .......................................... 6,079 6,013 Other accrued expenses .................................... 1,932 1,116 Hedge liability............................................ - 658 Current maturities of long-term debt ...................... 1,128 415 ------------------ ------------------- Total current liabilities ............................... 38,141 22,340 Long-term debt ............................................... 266,441 285,184 Deferred income taxes ........................................ 21,079 20,621 Future site restoration ..................................... 4,305 4,056 Minority interest in foreign subsidiary ...................... 12,097 - Commitments and contingencies Stockholders' equity (deficit): Common stock, par value $.01 per share - authorized 200,000,000 shares; issued 22,759,852 and 30,145,280 shares at December 31, 2000 and 2001, respectively ... 227 301 Additional paid-in capital ................................ 130,409 136,830 Accumulated deficit ...................................... (131,376) (151,094) Treasury stock, at cost, 165,883 shares at December 31, 2000 and 2001 ................................................ (964) (964) Accumulated other comprehensive income (loss).............. (4,799) (13,561) ------------------ ------------------- Total stockholders' equity (deficit)......................... (6,503) (28,488) ------------------ ------------------- Total liabilities and stockholders' equity (deficit)...... $ 335,560 $ 303,713 ================== ===================
See accompanying Notes to Consolidated Financial Statements. F-5
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31 --------------------------------------------------------- 1999 2000 2001 ------------------------------------------------------- (In thousands except per share data) Revenues: Oil and gas production revenues ......................... $ 59,025 $ 72,973 $ 73,201 Gas processing revenues ................................. 4,244 2,717 2,438 Rig revenues ............................................ 444 505 756 Other .................................................. 3,057 405 848 ------------------- ----------------- ------------- 66,770 76,600 77,243 Operating costs and expenses: Lease operating and production taxes .................... 17,938 18,783 18,616 Depreciation, depletion, and amortization ............... 34,811 35,857 32,484 Proved property impairment .............................. 19,100 - 2,638 Rig operations .......................................... 624 717 702 General and administrative .............................. 5,269 6,533 6,445 General and administrative (Stock-based compensation).... - 2,767 (2,767) ------------------- ----------------- -------------- 77,742 64,657 58,118 ------------------- ----------------- -------------- Operating income (loss)..................................... (10,972) 11,943 19,125 Other (income) expense: Interest income ......................................... (666) (530) (78) Amortization of deferred financing fees ................. 1,915 2,091 2,268 Interest expense ........................................ 36,815 31,140 31,523 (Gain) loss on sale of equity investment ................ - (33,983) 845 Other ................................................... - 1,563 207 ------------------- ----------------- -------------- 38,064 281 34,765 ------------------- ----------------- -------------- Income (loss) from operations before income tax and extraordinary item....................................... (49,036) 11,662 (15,640) Income tax expense (benefit): Current ................................................. 491 (1,233) 505 Deferred ................................................ (13,116) 4,938 1,897 Minority interest in income of consolidated foreign subsidiary (2001 prior to purchase)...................... 269 1,281 1,676 ------------------- ------------------ -------------- Income (loss) before extraordinary item..................... (36,680) 6,676 (19,718) Extraordinary item: Gain on debt extinguishment ............................. - 1,773 - ------------------- ------------------ --------------- Net income (loss)....................................... $ (36,680) $ 8,449 $ (19,718) =================== ================== =============== Basic earnings (loss) per common share: Net income (loss) before extraordinary item ............. $ (5.41) $ 0.29 $ (0.76) Extraordinary item ...................................... - 0.08 - ------------------- ------------------ ---------------- Net income (loss) per common share - basic .............. $ (5.41) $ 0.37 $ (0.76) =================== ================== ================ Diluted earnings (loss) per common share : Net income (loss) before extraordinary item ............. $ (5.41) $ 0.21 $ (0.76) Extraordinary item ...................................... - 0.05 - ------------------- ------------------ ---------------- Net income (loss) per common share - diluted............ $ (5.41) $ 0.26 $ (0.76) =================== ================== ================
See accompanying Notes to Consolidated Financial Statements. F-6
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 January 1, 1999 .... 6,501,441 $ 65 171,015 $ (1,167) $ 51,695 $ (103,145) $ $(10,970) $ (63,522) Comprehensive income (loss): Net loss ................. - - - - - (36,680) - (36,680) Other comprehensive income: Foreign currency translation adjustment. - - - - - - 14,572 14,572 --------- Comprehensive income (22,108) (loss) Issuance of common stock for compensation ...... 3,314 - (18,932) 96 (43) - - 53 Issuance of common stock in connection with Exchange Offer (Note 2, 5 and 6)............ 16,242,344 162 - - 75,910 - - 76,072 ----------- ---------- --------- ---------- ------------ ------------ ----------- ------------ Balance at December 31, 1999 22,747,099 $ 227 152,083 $ (1,071) $127,562 $ (139,825) $ 3,602 $ (9,505) Comprehensive income (loss): Net income............... - - - - - 8,449 - 8,449 Other comprehensive income: Foreign currency translation adjustment ........ - - - - - (8,401) - (8,401) ----------- Comprehensive income 48 Stock-based compensation expense.. - - - - 2,767 - - 2,767 Issuance of common stock and warrants for compensation .......... 12,753 - (25,000) 185 80 - - 265 Purchase of treasury stock ................. - - 38,800 (78) - - - (78) ------------ ---------- --------- ---------- ------------ ------------ ----------- ------------ Balance at December 31, 2000 22,759,852 $ 227 165,883 $ (964) $130,409 $ (131,376) $ (4,799) $ (6,503) ------------ ---------- --------- ---------- ------------ ------------ ----------- ------------
(continued) F-7
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)(continued) (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 January 1, 1999 .... 22,759,852 $ 227 165,883 $ (964) $130,409 $ (130,376) $ $ (4,799) $ (6,503) Comprehensive income (loss): Net loss................. - - - - - (19,718) - (19,718) Other comprehensive income: Hedge loss........... - - - - - - (566) (566) Foreign currency translation adjustment ........ - - - - - - (8,196) (8,196) ----------- Comprehensive loss - - - - - - - (28,480) Stock-based compensation expense................ - - - - (2,767) - - (2,767) Issuance of common stock for contingent value rights ................ 3,386,488 34 - - (34) - - - Issuance of common stock and stock options for acquisition of minority interest in Grey Wolf Exploration, Inc.................... 3,990,565 40 - - 9,206 - - 9,246 Stock options exercised . 8,375 - - - 16 - - 16 ------------ ---------- --------- ---------- ------------ ------------ ----------- ------------ Balance at December 31, 2001 30,145,280 $ 301 165,883 $ (964) $136,830 $ (151,094) $ (13,561) $ (28,488) ============ ========== ========= ========== ===========- ============ =========== ============
See accompanying Notes to Consolidated Financial Statements. F-8
F-11 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31 ---------------------------------------------------------- 1999 2000 2001 ------------------ ------------------ ------------------- (In thousands) Operating Activities Net income (loss) ........................ $ (36,680) $ 8,449 $ (19,718) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority interest in income of foreign subsidiary ................ 269 1,281 1,676 Extraordinary gain on extinguishment of debt............. - (1,773) - (Gain) loss on sale of equity investment......................... - (33,983) 845 Depreciation, depletion, and amortization ...................... 34,811 35,857 32,484 Proved property impairment .......... 19,100 - 2,638 Deferred income tax (benefit) expense (13,116) 4,938 1,897 Amortization of deferred financing fees............................... 1,915 2,091 2,268 Amortization of premium on long term debt............................... (579) - - Stock-based compensation ............ - 2,767 (2,767) Issuance of common stock and warrants for compensation ......... 53 265 - Changes in operating assets and liabilities: Accounts receivable ............. (2,698) (7,036) 12,693 Equipment inventory ............. 57 (538) (76) Other .......................... 396 (1,839) (106) Accounts payable ................ (744) 11,318 (14,848) Accrued expenses ................ 1,098 (425) (723) ------------------ ------------------ ---------------- Net cash provided by operating activities 3,882 21,372 16,263 Investing Activities Capital expenditures, including purchases and development of properties ......... (128,708) (74,412) (57,056) Proceeds from sale of oil and gas properties............................. 17,494 21,157 28,938 Acquisition of minority interest.......... - - (2,679) Proceeds from sale of equity investment .. - 34,482 - ------------------ ------------------ ---------------- Net cash used in investing activities .... (111,214) (18,773) (30,797)
F-9
Abraxas Petroleum Corporation and Subsidiaries Consolidated Statements of Cash Flows (continued) Year Ended December 31 ---------------------------------------------------------- 1999 2000 2001 ------------------ ------------------ ------------------ (In thousands) Financing Activities Purchase of treasury stock, net ............ $ - $ (78) $ - Proceeds from issuance of common ock...... - - 16 Proceeds from long-term borrowings ......... 88,457 6,400 29,995 Payments on long-term borrowings ........... (35,747) (10,163) (9,326) Deferred financing fees .................... (3,586) 23 - ------------------ ------------------ ------------------- Net cash provided by (used in) financing activities .............................. 49,124 (3,818) 20,685 ------------------ ------------------ ------------------- Increase (decrease) in cash ................ (58,208) (1,219) 6,151 ------------------ ------------------ ------------------- Effect of exchange rate changes on cash .... 617 (576) (550) ------------------ ------------------ ------------------- Increase (decrease) in cash ................ (57,591) (1,795) 5,601 Cash at beginning of year .................. 61,390 3,799 2,004 ------------------ ------------------ ------------------- Cash at end of year................... $ 3,799 $ 2,004 $ 7,605 ================== ================== =================== Supplemental Disclosures Supplemental disclosures of cash flow information: Interest paid ......................... $ 35,979 $ 33,004 $ 31,752 ================== ================== =================== Taxes paid............................. $ - $ - $ 505 ================== ================== =================== Supplemental schedule of noncash investing and financing activities: In December 1999 the Company completed the exchange of $269,699,000 of its 11.5% Old Notes for $188,778,000 of new Second Lien Notes, issuance of up to 16,078,990 shares of common stock and contingent value rights. An additional $5,000,000 of the Second Lien Notes were issued for payment of fees and expenses. See Note 2, 5 and 6. Decrease in long-term debt......... $ 75,921 ================== Increase in stockholder's equity... $ 75,921 ================== In May 2001 the Company issued 3,386,488 shares of common stock upon the expiration of the CVRs issued in connection with the December 1999 exchange. See Note 6. In September 2001 the Company issued 3,990,565 shares of common stock and options and paid $2,679,000 million in cash in connection with the acquisition of the minority interest in Grey Wolf. See Note 3. Decrease in oil and gas properties and other assets...................... $ (2,925) ===================== Decrease in deferred income tax liability................................ $ 1,091 ===================== Increase in stockholders equity.......................................... $ (9,246) ===================== Decrease in minority interest in foreign subsidiary...................... $ 13,759 =====================
See accompanying Notes to Consolidated Financial Statements. F-10 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 2000, and 2001 1. Organization and Significant Accounting Policies Nature of Operations Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an independent energy company engaged in the exploration for and the acquisition, development, and production of crude oil and natural gas primarily along the Texas Gulf Coast, in the Permian Basin of western Texas and in Canada and the processing of natural gas primarily in Canada. The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. 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 represents the minority shareholders' proportionate share of the equity and income of Grey Wolf prior to the Company's acquisition of the remaining interest in September 2001. Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management believes that it is reasonably possible that estimates of proved crude oil and natural gas revenues could significantly change in the future. Concentration of Credit Risk Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables, interest rate and crude oil and natural gas price swap agreements. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. Equipment Inventory Equipment inventory principally consists of casing, tubing, and compression equipment and is carried at the lower of cost or market. Oil and Gas Properties The Company follows the full cost method of accounting for crude oil and natural gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization ("DD&A") of capitalized crude oil and natural gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of crude oil and natural gas properties, less related deferred taxes, are limited, by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Excess costs are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of crude oil and natural gas properties, except in unusual circumstances - see Note 3. F-11 Unproved properties represent costs associated with properties on which the Company is performing exploration activities or intends to commence such activities. These costs are reviewed periodically for possible impairments or reduction in value based on geological and geophysical data. If a reduction in value has occurred, costs being amortized are increased. The Company believes that the unproved properties will be substantially evaluated in six to thirty-six months and it will begin to amortize these costs at such time. During 1999, 2000 and 2001, the Company capitalized $193,000, $589,000 and $164,000 of interest expense, respectively, based on the cost of major development projects in progress. Other Property and Equipment Other property and equipment are recorded on the basis of cost. Depreciation of gas gathering and processing facilities and other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and betterments are recorded as additions to the property and equipment accounts. Repairs that do not improve or extend the useful lives of assets are expensed. Turnaround costs Turnaround costs represent major maintenance performed on the Company's gas processing plants and are expensed as incurred. Hedging The Company periodically enters into agreements to hedge the risk of future crude oil and natural gas price fluctuations. Such agreements, primarily in the form of price swaps, may either fix or support crude oil and natural gas prices or limit the impact of price fluctuations with respect to the Company's sale of crude oil and natural gas. Gains and losses on such hedging activities are recognized in oil and gas production revenues when hedged production is sold. The net cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production required by the contract is delivered. Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities", is effective for the Company on January 1, 2001. SFAS 133, as amended and interpreted, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. All derivatives, whether designated in hedging relationships or not, will be required to be recorded on the balance sheet at fair value. If the derivative is designated a fair-value hedge, the changes in the fair value of the derivative and the hedged item will be recognized in earnings. If the derivative is designated a cash-flow hedge, changes in the fair value of the derivative will be recorded in other comprehensive income (OCI) and will be recognized in the income statement when the hedged item affects earnings. SFAS 133 defines new requirements for designation and documentation of hedging relationships as well as ongoing effectiveness assessments in order to use hedge accounting. For a derivative that does not qualify as a hedge, changes in fair value will be recognized in earnings. Stock-Based Compensation The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock. Effective July 1, 2000, the Financial Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock Compensation", an interpretation of APB No. 25. Under the interpretation, certain modifications to fixed stock option awards which were made subsequent to December 15, 1998, and were 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, the Company amended the exercise price to $2.06 on all options with an existing exercise price greater than $2.06. See Note 7. The Company recognized approximately $2.8 million in expense during 2000 and a credit of $2.8 million during 2001 as General and Administrative (Stock-based compensation). The credit for the year ended December 31, 2001 was due to a decline in the Company's common stock price. F-12 Foreign Currency Translation The functional currency for Canadian Abraxas and Grey Wolf is the Canadian dollar ($CDN). The Company translates the functional currency into U.S. dollars ($US) based on the current exchange rate at the end of the period for the balance sheet and a weighted average rate for the period on the statement of operations. Translation adjustments are reflected as Accumulated Other Comprehensive Income (Loss) in Stockholders' Equity (Deficit). Fair Value of Financial Instruments The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the book value. The Company assumes the book value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments. Restoration, Removal and Environmental Liabilities The estimated costs of restoration and removal of major processing facilities are accrued on a straight-line basis over the life of the property. The estimated future costs for known environmental remediation requirements are accrued when it is probable that a liability has been incurred and the amount of remediation costs can be reasonably estimated. These amounts are the undiscounted, future estimated costs under existing regulatory requirements and using existing technology. Revenue Recognition The Company recognizes crude oil and natural gas revenue from its interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. Revenue from the processing of natural gas is recognized in the period the service is performed. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. Management does not believe that the Company had material gas imbalances at December 31, 2000 or 2001. Deferred Financing Fees Deferred financing fees are being amortized on a level yield basis over the term of the related debt arrangements. Income Taxes The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. New Accounting Pronouncements In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations, which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. The Company has applied these standards to its purchase of the minority interest in Grey Wolf. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires an asset retirement obligation to be recorded at fair value during the period incurred and an equal amount recorded as an increase in the value of the related long-lived asset. The capitalized cost is depreciated over the useful life of the asset and the obligation is accreted to its present value each period. SFAS No. 143 is effective for the Company beginning January 1, 2003 with earlier adoption encouraged. The Company is currently evaluating the impact the standard will have on its future results of operations and financial condition. F-13 In August 2001, the FASB issued SFAS No. 144 Accounting for the Impairment of Disposal of Long-Lived Assets. SFAS No. 144 retains the requirement to recognize an impairment loss only where the carrying value of a long-lived asset is not recoverable from its undiscounted cash flows and to measure such loss as the difference between the carrying amount and fair value of the asset. SFAS No. 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from the discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. The Company adopted the accounting standard effective January 1, 2002, which did not have a significant impact on the Company's financial condition or results of operations. Reclassifications Certain prior years balances have been reclassified for comparative purposes. 2. Liquidity At December 31, 2001 the Company's current liabilities of approximately $22.3 million exceeded its current assets of $17.3 million. Included in current liabilities are trade payables of $10.5 million, revenues due third parties of $3.6 million and accrued interest of $6.0 million. The Company's results of operations in 2001 generated $16.3 million in cash flows from operations. 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 raisi ng 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. There can be no assurance that any of the above alternatives, or some combination thereof, will be available or, if available, will be on terms acceptable to the Company. The Company will have 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 new financing agreement entered into in December 2001, see discussion below. The First Lien Notes indenture, the Second Lien Notes indenture and the Old Notes indenture substantially limit its use of proceeds from asset sales. Should commodity prices not increase from levels at December 31, 2001, most of the Company's capital expenditures are discretionary and can be delayed to maintain current liquidity. 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 additional properties will be adequate to fund operations and planned capital expenditures. The Company's wholly owned Canadian subsidiaries, Canadian Abraxas and Grey Wolf, have 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. See Note 19. F-14 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. 3. Acquisitions and Divestitures New Cache Petroleums LTD Acquisition In January 1999, Canadian Abraxas completed the acquisition of New Cache Petroleums, LTD ("New Cache"), for approximately $78 million in cash and the assumption of approximately $10 million in debt. The debt was paid off with a portion of the proceeds from the sale of the First Lien Notes. The acquisition was accounted for as a purchase, and the purchase price was allocated to the crude oil and natural gas properties based on the fair values of the properties acquired. Results of operations for New Cache have been included in the consolidated financial statements since January 1999. Abraxas Wamsutter L.P. Divestiture In November 1998, the Company sold its interest in certain Wyoming properties to Abraxas Wamsutter L.P., a Texas limited partnership (the "Partnership"), for approximately $58.6 million and a minority equity ownership in the Partnership. Wamsutter Holdings, Inc. ("Wamsutter") initially owned a one percent interest and acted as general partner of the Partnership. The investment in the Partnership was accounted for by the equity method. After certain payback requirements were satisfied, the Company's interest would increase to 35% initially and could increase to as high as 65%. The Company also received a management fee and reimbursement of certain overhead costs from the Partnership which amounted to $594,700 and $112,700 for the years ended December 31, 1999 and 2000 respectively. In March 2000, the Partnership sold all of its interest in its crude oil and natural gas properties to a third party. Prior to the sale of these properties, effective January 1, 2000, the Company's equity investee share of oil and gas property cost, results of operations and amortization were not material to consolidated operations or financial position. As a result of the sale, the Company received approximately $34 million, which represented a proportional interest in the Partnership's proved properties. See Note 10 regarding a litigation provision in 2001 of $845,000 related to ad valorem taxes. The condensed pro forma financial information presented below summarizes on an unaudited pro forma basis, approximate results of the Company's consolidated results of operations for the year ended December 31, 1999, assuming the divestiture had occurred on January 1, 1999. (In thousands except per share data) ----------------------- Revenue ..................................... $ 66,770 ======================= Net loss .................................... $ (3,294) ======================= Loss per common share ....................... $ (0.49) ======================= Acquisition of Minority Interest in Grey Wolf In September 2001, the Company completed a tender offer for the minority interest in Grey Wolf, acquiring the approximately 52% of capital stock that was not previously owned by the Company. The Company issued 3,990,565 common shares and 588,916 stock options, valued together at approximately $9.2 million. Additionally, the Company incurred direct costs of approximately $2.7 million related to the acquisition. The elimination of the minority interest through an acquisition at a purchase price less than Grey Wolf's book value in the Company's consolidated financial statements had the effect of reducing the property and other assets balances by $2.9 million and deferred income taxes by $1.1 million. The condensed pro forma financial information presented below summarizes, on an unaudited pro forma basis, approximate results of the Company's consolidated results of operations for the years ended December 31, 1999, 2000 and 2001, assuming the acquisition of the minority interest in Grey Wolf had occurred at the beginning of each period presented. F-15
Years ended December 31, 1999 2000 2001 -------------- -------------- ----------- (In thousands except per share items) -------------------------------------------- Revenue .................................... $ 66,770 $ 76,600 $ 77,243 ============== ============= ========== Income (loss) before extraordinary item .... (36,411) 7,957 (18,042) ============== ============= ========== Net income (loss) ........................... (36,411) 9,730 (18,042) ============== ============= ========== Income (loss) before extraordinary item, per common share - basic ..................... (3.38) 0.30 (0.63) ============== ============= ========== Net income (loss) per common share - basic (3.38) 0.37 (0.63) ============== ============= ========== Income (loss) before extraordinary item, per common share - diluted ................... (3.38) 0.22 (0.63) ============== ============= ========== Net income (loss) per common share - diluted (3.38) 0.27 (0.63) ============== ============= ==========
4. Property and Equipment The major components of property and equipment, at cost, are as follows:
Estimated December 31 ---------------------------------- Useful Life 2000 2001 -------------- ---------------- ----------------- Years (In thousands) Land, buildings, and improvements .............. 15 $ 318 $ 318 Crude oil and natural gas properties ........... - 494,633 496,724 Natural gas processing plants .................. 18 60,299 63,964 Equipment and other ............................ 7 3,103 3,350 ---------------- ----------------- $ 558,353 $ 564,356 ================ =================
5. Long-Term Debt Long-term debt consists of the following:
December 31 ---------------------------------- 2000 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 Grey Wolf Credit facility repaid in 2001.......................... 7,859 - 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 $2.3 million discount...................................... - 22,944 Production Payment ................................................... 5,231 8,176 ---------------- ---------------- 267,569 285,599 Less current maturities ............................................... 1,128 415 ---------------- ---------------- $ 266,441 $ 285,184 ================ ================
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. F-16 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. 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 in certain situations as described in the First Lien Notes indenture. F-17 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 The fair value of the Old Notes, First Lien Notes and Second Lien Notes was approximately $235.2 million as of December 31, 2001. The Company has approximately $325,000 of standby letters of credit and a $10,000 performance bond open at December 31, 2001. Approximately $336,000 of cash is restricted and in escrow related to certain of the letters of credit and the bond. Grey Wolf Facility 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 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. F-18 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 the Miranat 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 the 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 December 31, 2001, the Company had received $22.1 million under this agreement. The outstanding balance as of December 31, 2001 is $8.2 million. F-19 Extraordinary Item In June 2000, the Company retired $3.5 million of the Old Notes and $3.6 million of the Second Lien Notes at a discount of $1.8 million. 6. Stockholders' Equity Common Stock In 1994, the Board of Directors adopted a Stockholders' Rights Plan and declared a dividend of one Common Stock Purchase Right ("Rights") for each share of common stock. The Rights are not initially exercisable. Subject to the Board of Directors' option to extend the period, the Rights will become exercisable and will detach from the common stock ten days after any person has become a beneficial owner of 20% or more of the common stock of the Company or has made a tender offer or Exchange Offer (other than certain qualifying offers) for 20% or more of the common stock of the Company. Once the Rights become exercisable, each Right entitles the holder, other than the acquiring person, to purchase for $40 a number of shares of the Company's common stock having a market value of two times the purchase price. The Company may redeem the Rights at any time for $.01 per Right prior to a specified period of time after a tender or Exchange Offer. The Rights will expire in November 2004, unless earlier exchanged or redeemed 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. In May 2001, Abraxas issued 3,386,488 shares upon the expiration of the CVRs. Treasury Stock In March 1996, the Board of Directors authorized the purchase in the open market of up to 500,000 shares of the Company's outstanding common stock, the aggregate purchase price not to exceed $3,500,000. During the year ended December 31, 2000, 38,800 shares with an aggregate cost of $78,000 were purchased. During the years ended December 31, 1999 and 2001, the Company did not purchase any shares of its common stock for treasury stock. 7. Stock Option Plans and Warrants Stock Options The Company grants options to its officers, directors, and key employees under various stock option and incentive plans. During 2001, the Company's stockholders approved an amendment to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan to increase the number of shares of Abraxas common stock reserved for issuance under the plan to 5,000,000. The additional shares were necessary to accommodate the grant of Abraxas options to Grey Wolf option holders in connection with the acquisition of the minority interest in Grey Wolf in September 2001 (see Note 3), and for the re-issuance of outstanding options granted under the Abraxas Petroleum Corporation 2000 Long Term Incentive Plan, which was terminated in 2001. The options were re-issued at the same exercise price and term as the original issuances. The Company's various stock option plans have authorized the grant of options to management, employees and directors for up to approximately 5.6 million shares of the Company's common stock. All options granted have ten year terms and vest and become fully exercisable over three to four years of continued service at 25% to 33% on each anniversary date. At December 31, 2001 approximately 695,000 options remain available for grant. Pro forma information regarding net income (loss) and earnings (loss) per share is required by SFAS 123, "Accounting for Stock-Based Compensation", which also requires that the information be determined as if the Company has accounted for its employee stock options granted subsequent to December 31, 1995 under the fair value method prescribed by that SFAS. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1999, 2000, and 2001, risk-free interest rates of 6.25%, 6.25% and 3.50%, respectively; dividend yields of -0-%; volatility factors of the expected market price of the Company's common stock of .928, .916 and .35, respectively; and a weighted-average expected life of the option of ten years. F-20 The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information follows:
1999 2000 2001 --------------------------------------------- (In thousands except per share data) Pro forma net income (loss) ............................ $ (37,240) $ 10,089 $ (21,002) Pro forma net income (loss) per common share ........... $ (5.49) $ 0.45 $ (0.81) Pro forma net income (loss) per common share - diluted $ (5.49) $ 0.31 $ (0.81)
A summary of the Company's stock option activity, and related information for the years ended December 31, follows:
1999 2000 2001 ----------------------------- ----------------------------- ----------------------------- Weighted-Average Weighted-Average Weighted-Average Options Exercise Price(1) Options Exercise Price Options Exercise Price (000s) (000s) (000s) (2) ---------- ------------------ ---------- ------------------ --------- ------------------ Outstanding-beginning of year ................... 1,572 $ 7.33 1,890 $ 1.82 4,042 $ 3.37 Granted ................... 534 1.19 2,240 4.62 918 2.81 Exercised ................. - - - - (8) 1.95 Forfeited/Expired ......... (216) 2.06 (88) 1.89 (10) 1.79 ---------- ---------- --------- Outstanding-end of year ... 1,890 $ 1.82 4,042 $ 3.37 4,942 $ 3.28 ========== ========== ========= Exercisable at end of year 685 $ 2.06 1,067 $ 1.99 2,259 $ 2.65 ========== ========== ========= Weighted-average fair value of options granted during the year $ 1.07 $ 1.21 $ 1.19
Exercise prices for options outstanding as of December 31, 2001 ranged from $0.97 to $5.03. The weighted-average remaining contractual life of those options is approximately 7 years. (1) In March 1999, the Company amended the exercise price to $2.06 per share on all options with an existing exercise price greater than $2.06. See Note 1 Stock-based compensation. (2) In September 2001, the Abraxas Petroleum Corporation 2000 Long Term Incentive Plan was terminated, and options granted under the plan were reissued under the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan at the same option price and term. Stock Awards In addition to stock options granted under the plans described above, the 1994 Long-Term Incentive Plan also provides for the right to receive compensation in cash, awards of common stock, or a combination thereof. In 1999, the Company made direct awards of common stock of 18,932 shares at weighted average fair values of $5.09 per share. The Company recorded compensation expense of $37,900 for the year ended December 31, 1999. There were no awards in 2000 or 2001. F-21 The Company also has adopted the Restricted Share Plan for Directors which provides for awards of common stock to nonemployee directors of the Company who did not, within the year immediately preceding the determination of the director's eligibility, receive any award under any other plan of the Company. In 1999 and 2000, the Company made direct awards of common stock of 3,314 shares and 12,753 shares, respectively, at weighted average fair values of $4.38 and $0.94 per share, respectively. The Company recorded compensation expense of $13,700 and $11,900 for the years ended December 31, 1999 and 2000, respectively. There were no direct awards of common stock in 2001. During 1996, the Company's stockholders approved the Abraxas Petroleum Corporation Director Stock Option Plan (Plan), which authorizes the grant of nonstatutory options to acquire an aggregate of 104,000 common shares to those persons who are directors and not officers of the Company. In March 1999 each of the seven eligible directors were granted an option to purchase 2,000 common shares at $2.06, in November 1999 five of the eligible directors were granted options to purchase 15,000 common shares at $1.41. In December 1999 a new board was appointed in connection with the Company's Exchange Offer, each of the four new eligible directors were granted options for 75,000 common shares at $0.97. Stock Warrants and Other In 2000, the Company issued 950,000 warrants in conjunction with a consulting agreement. Each is exercisable for one share of common stock at an exercise price of $3.50 per share. These warrants have a four-year term beginning July 1, 2000. The Company recorded approximately $219,000 of compensation expense which is included in Other expense in 2000. In addition, the Company paid cash compensation of $360,000 and $191,000 in 2000 and 2001, respectively, under the agreement. At December 31, 2001, the Company has approximately 6.6 million shares reserved for future issuance for conversion of its stock options, warrants, and incentive plans for the Company's directors, employees and consultants. 8. Income Taxes Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company's deferred tax liabilities and assets are as follows: December 31 -------------------- 2000 2001 -------- -------- (In thousands) Deferred tax liabilities: U.S. full cost pool ..................... $ 2,359 $ 2,714 Canadian full cost pool ................. 21,079 24,809 -------- -------- Total deferred tax liabilities ............ 23,438 27,523 Deferred tax assets: Depletion ............................... 1,439 2,035 Net operating losses ("NOL") ........... 34,624 42,264 Other ................................... 1,059 2,273 -------- -------- Total deferred tax assets ................. 37,122 46,572 Valuation allowance for deferred tax assets (34,763) (39,670) -------- -------- Net deferred tax assets ................... 2,359 6,902 -------- -------- Net deferred tax liabilities .............. $ 21,079 $ 20,621 ======== ======== Significant components of the provision (benefit) for income taxes are as follows: 1999 2000 2001 ---------- ----------- ----------- Current: Federal..................... $ - $ - $ 505 Foreign .................... 491 (1,233) - ---------- ----------- ----------- $ 491 $ (1,233) $ 505 ========== =========== =========== Deferred: Federal ..................... $ - $ 3,433 $ - Foreign ..................... (13,116) 1,505 1,897 ---------- ----------- ----------- $(13,116) $ 4,938 $ 1,897 ========== =========== =========== F-22 As a result of the acquisition described in Note 3, deferred tax liabilities decreased by $1,091,000. 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 US $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 $34,763,000 and $39,670,000 for deferred tax assets at December 31, 2000 and 2001, respectively. The reconciliation of income tax attributable to continuing operations computed at the U.S. federal statutory tax rates to income tax expense is: December 31 --------------------------------------------- 1999 2000 2001 -------------- --------------- -------------- (In thousands) Tax (expense) benefit at U.S. statutory rates (34%) ...... $ 16,672 $ (3,965) $ 5,318 (Increase) decrease in deferred tax asset valuation allowance ................... (3,312) 1,371 (4,907) NOL utilization - extraordinary gain -........ - (603) - Write-down of non-tax basis assets....................... - - (2,194) Higher effective rate of foreign operations......... (491) (1,098) (136) Percentage depletion ......... - 363 596 Other ........................ (244) 227 (1,079) -------------- --------------- -------------- $ 12,625 $ (3,705) $ (2,402) ============== =============== ============== F-23 9. Related Party Transactions Accounts receivable - Other and Other assets includes approximately $268,000 and $195,000 as of December 31, 2000 and 2001, respectively, representing amounts due from officers and stockholders relating primarily to joint interest billings on properties which the Company operates and advances made to employees. Grey Wolf owns a 10% interest in the Canadian Abraxas oil and gas properties and the Canadian Abraxas gas processing plants acquired by Canadian Abraxas in November 1996 and manages the operations of Canadian Abraxas, pursuant to a management agreement between Canadian Abraxas and Grey Wolf. Under the management agreement, Canadian Abraxas reimburses Grey Wolf for reasonable costs or expenses attributable to Canadian Abraxas and for administrative expenses based upon the percentage that Canadian Abraxas' gross revenue bears to the total gross revenue of Canadian Abraxas and Grey Wolf. Amounts paid under this agreement were $2.3 million, $2.5 million and $1.7 million for the years ended December 31, 1999, 2000 and 2001, respectively. Wind River Resources Corporation ("Wind River"), all of the capital stock of which is owned by the Company's President, owns a twin-engine airplane. The airplane is available for business use by the employees of Abraxas from time to time at Wind River's cost. Abraxas paid Wind River a total of $336,000, $336,000 and $314,000 in 1999, 2000 and 2001 respectively. 10. Commitments and Contingencies Operating Leases During the years ended December 31, 1999, 2000 and 2001, the Company incurred rent expense related to leasing office facilities of approximately $396,000, $465,000 and $519,000, respectively. Future minimum rental payments are as follows at December 31, 2001. 2002............................................. $ 528,000 2003 ............................................ 336,000 2004 ............................................ 236,000 2005 ............................................ 236,000 2006 ............................................ 177,000 Thereafter ...................................... - Litigation and Contingencies In 2001 the Company and the Partnership (see Note 3) 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 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 has 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 December 31, 2001, 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. F-24 11. Earnings per Share The following table sets forth the computation of basic and diluted earnings per share:
1999 2000 2001 ------------------ ----------------- --------------- Numerator: Numerator for basic and diluted earnings per share - net income (loss) before extraordinary item $ (36,680,000) $ 6,676,000 $ (19,718,000) Extraordinary item - 1,773,000 - ------------------ ----------------- --------------- Numerator for basis and diluted earnings per share - net income (loss) available to common stockholders (36,680,000) 8,449,000 (19,718,000) ================== ================= =============== Denominator: Denominator for basic earnings per share - weighted-average shares 6,783,633 22,615,777 25,788,571 Effect of dilutive securities: Stock options, warrants and CVRs - 10,011,987 - ------------------ ----------------- --------------- Dilutive potential common shares Denominator for diluted earnings per share - adjusted weighted-average shares and assumed conversions 6,783,633 32,627,764 25,788,571 ================== ================= =============== Basic earnings (loss) per share: Net income (loss) before extraordinary item $ (5.41) $ 0.29 $ (0.76) Extraordinary item - 0.08 - ---------------- ----------------- --------------- Net income (loss) per common share $ (5.41) $ 0.37 $ (0.76) ================== ================= =============== Diluted earnings (loss) per share: Net income (loss) before extraordinary item $ (5.41) $ 0.21 $ (0.76) Extraordinary item - 0.05 - ------------------ ----------------- --------------- Net income (loss) per common share - diluted $ (5.41) $ 0.26 $ (0.76) ================== ================= ===============
For the year ended December 31, 1999 and 2001 none of the shares issuable in connection with stock options, warrants or CVRs are included in diluted shares. Inclusion of these shares would be antidilutive due to losses incurred in that year. Had a loss not been incurred, 68.2 million shares and 1.2 million shares would have been included for the year ended December 31, 1999 and 2001, respectively. 12. Quarterly Results of Operations (Unaudited) Selected results of operations for each of the fiscal quarters during the years ended December 31, 2000 and 2001 are as follows: 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter --------- ---------- --------- --------- (In thousands, except per share data) Year Ended December 31, 2000 Net revenue ................... $ 16,717 $ 16,287 $ 16,377 $ 27,219 Operating income (loss) ....... 1,513 1,629 (963) 9,404 Net income (loss) before extraordinary item .......... 27,156 (7,186) (13,586) 292 Net income (loss) ............. 27,156 (5,413) (13,586) 292 Net income (loss) before extraordinary item per common share- basic ......... $ 1.20 $ (0.32) $ (0.60) $ 0.01 Net income (loss) before extraordinary item per common share - diluted ............ $ 0.52 $ (0.32) $ (0.60) $ 0.01 F-25 Net income (loss) per common share- basic ................ $ 1.20 $ (0.24) $ (0.60) $ 0.01 (0.60) Net income (loss) per common share- diluted .............. $ 0.52 $ (0.24) $ (0.60) $ 0.01 Year Ended December 31, 2001 Net revenue ................... $ 29,086 $ 21,116 $ 14,901 $ 12,140 Operating income (loss) ....... 12,112 9,002 2,113 (4,102) Net income (loss) ............. 255 (1,274) (5,849) (12,850) Net income (loss) per common share- basic ................ $ 0.01 $ (0.05) $ (0.22) $ (0.43) Net income (loss) per common share- diluted .............. $ 0.01 $ (0.05) $ (0.22) $ (0.43) During the first quarter of 2000, the Company recognized a gain of $34 million on the sale of its equity investment in the Partnership. In the second quarter of 2000, the Company recognized an extraordinary gain on debt extinguishment of $1.8 million. During the fourth quarter of 2001, the Company incurred a ceiling limitation write-down of $2.6 million, which was determined using realized prices at March 22, 2002. Had year-end 2001 realized prices been used, the write-down would have been $71.3 million. 13. Benefit Plans The Company has a defined contribution plan (401(k)) covering all eligible employees of the Company. The Company did not contribute to the plan in 2000 or 2001. The employee contribution limitations are determined by formulas, which limit the upper one-third of the plan members from contributing amounts that would cause the plan to be top-heavy. The employee contribution is limited to the lesser of 20% of the employee's annual compensation or $11,000. 14. Guarantor Condensed Consolidation 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 of December 31, 2000 and 2001 and the related consolidating statements of operations for the years ended December 31, 1999, 2000 and 2001. Canadian Abraxas (one of the Restricted Subsidiaries, see Note 5) 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 and the Old Notes.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet December 31, 2001 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and 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 F-26 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 ............................... 108,801 784 6,281 (115,321) 545 -------------- --------------- ------------- ------------ -------------- Total assets ............................ $ 250,227 $ 126,626 $ 58,989 $ (132,129) $ 303,713 ============== =============== ============= ============ ============== 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 Stockholders' equity (deficit)................... 23,069 34,642 22,945 (109,144) (28,488) -------------- --------------- ------------- ------------ -------------- Total liabilities and stockholders' equity (deficit)........................................ $ 250,227 $ 126,626 $ 58,989 $ (132,129) $ 303,713 ============== =============== ============= ============ ==============
(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 (see Note 5).
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Balance Sheet December 31, 2000 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------------------------ ----------------- Assets: Current assets: Cash .................................... $ 326 $ 1,678 $ - $ - $ 2,004 Accounts receivable, less allowance for doubtful accounts...................... 46,085 2,890 6,434 (34,691) 20,718 Equipment inventory ..................... 985 319 107 - 1,411 Other current assets .................... 179 - - - 179 --------------- -------------- ------------- ---------------- ----------------- Total current assets .................. 47,575 4,887 6,541 (34,691) 24,312 Property and equipment - net................ 119,349 148,585 36,850 - 304,784 Deferred financing fees, net .............. 4,116 1,440 - - 5,556 Other assets ............................... 96,666 832 - (96,590) 908 --------------- -------------- ------------- ---------------- ----------------- Total assets ............................ $ 267,706 $ 155,744 $ 43,391 $ (131,281) $ 335,560 =============== ============== ============= ================ ================= Liabilities and Stockholder's deficit: Current liabilities: Accounts payable ............................. $ 23,028 $31,437 $ 8,891 $ (34,354) $ 29,002 Accrued interest ............................. 5,057 1,009 13 - 6,079 Other accrued expenses ....................... 679 (349) 1,602 - 1,932 Current maturities of long-term debt ......... 1,128 - - - 1,128 --------------- -------------- ------------- ---------------- ----------------- Total current liabilities .................. 29,892 32,097 10,506 (34,354) 38,141 Long-term debt .................................. 205,953 52,629 7,859 - 266,441 Deferred income taxes ........................... - 18,881 2,198 - 21,079 Future site restoration ........................ - 3,706 599 - 4,305 F-27 Minority interest in foreign subsidiary ......... - - - 12,097 12,097 --------------- -------------- ------------- ---------------- ----------------- 235,845 107,313 21,162 (22,257) 342,063 Stockholders' equity (deficit)................... 31,861 48,431 22,229 (109,024) (6,503) --------------- -------------- ------------- ---------------- ----------------- Total liabilities and stockholders' equity (deficit)........................................ $ 267,706 $ 155,744 $ 43,391 $(131,281) $ 335,560 =============== ============== ============= ================ =================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the year ended December 31, 2001 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------- --------------- --------------- Revenues: Oil and gas production revenues ............... $ 34,934 $ 24,308 $ 13,959 $ - $ 73,201 Gas processing revenues ....................... - 2,008 430 - 2,438 Rig revenues .................................. 756 - - - 756 Other ........................................ 85 471 292 - 848 --------------- -------------- ------------- --------------- --------------- 35,775 26,787 14,681 - 77,243 Operating costs and expenses: Lease operating and production taxes .......... 9,302 6,836 2,478 - 18,616 Depreciation, depletion, and amortization ..... 12,336 14,707 5,441 - 32,484 Proved property impairment .................... - 2,638 - - 2,638 Rig operations ................................ 702 - - - 702 General and administrative .................... 3,742 1,720 983 - 6,445 General and administrative (Stock-based Compensation)................................ (2,767) - - - (2,767) --------------- -------------- ------------- --------------- --------------- 23,315 25,901 8,902 - 58,118 --------------- -------------- ------------- --------------- --------------- Operating income (loss)........................... 12,460 886 5,779 - 19,125 Other (income) expense: Interest income ............................... (1,242) - - 1,164 (78) Amortization of deferred financing fees........ 1,907 361 - - 2,268 Interest expense............................... 25,086 7,117 484 (1,164) 31,523 Other ......................................... 1,052 - - - 1,052 --------------- -------------- ------------- --------------- --------------- 26,803 7,478 484 - 34,765 --------------- -------------- ------------- --------------- --------------- Income (loss) from operations before income tax - and extraordinary item......................... (14,343) (6,592) 5,295 (15,640) Income tax expense (benefit)...................... 505 (80) 1,977 - 2,402 Minority interest in income of consolidated foreign subsidiary ............................ - - - (1,676) (1,676) --------------- -------------- ------------- --------------- --------------- Net income (loss)................................ $ (14,848) $ (6,512) $ 3,318 $ (1,676) $ (19,718) =============== =============- ============= =============== ================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the year ended December 31, 2000 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------- --------------- --------------- Revenues: Oil and gas production revenues ............... $ 32,165 $ 27,425 $ 13,383 $ - $ 72,973 F-28 Gas processing revenues ....................... - 2,271 446 - 2,717 Rig revenues .................................. 505 - - - 505 Other ........................................ 216 170 19 - 405 --------------- -------------- ------------- --------------- --------------- 32,886 29,866 13,848 - 76,600 Operating costs and expenses: Lease operating and production taxes .......... 7,755 8,695 2,333 - 18,783 Depreciation, depletion, and amortization ..... 12,328 18,126 5,403 - 35,857 Rig operations ................................ 717 - - - 717 General and administrative .................... 4,115 1,484 934 - 6,533 General and administrative (Stock-based Compensation)................................ 2,767 - - - 2,767 --------------- -------------- ------------- --------------- --------------- 27,682 28,305 8,670 - 64,657 --------------- -------------- ------------- --------------- --------------- Operating income (loss)........................... 5,204 1,561 5,178 - 11,943 Other (income) expense: Interest income ............................... (2,277) - - 1,747 (530) Amortization of deferred financing fees........ 1,660 431 - - 2,091 Interest expense .............................. 24,594 7,582 711 (1,747) 31,140 Gain on sale of equity investment ............. (33,983) - - - (33,983) Other ......................................... 1,116 447 - - 1,563 --------------- -------------- ------------- --------------- --------------- (8,890) 8,460 711 - 281 --------------- -------------- ------------- --------------- --------------- Income (loss) from operations before income tax and extraordinary item......................... 14,094 (6,899) 4,467 - 11,662 Income tax expense (benefit)...................... 3,433 (1,658) 1,930 - 3,705 Minority interest in income of consolidated 112 foreign subsidiary ............................ - - - (1,281) (1,281) --------------- -------------- ------------- --------------- --------------- Income (loss) before extraordinary item........... 10,661 (5,241) 2,537 (1,281) 6,676 Extraordinary item: Gain on debt extinguishment.................... 1,773 - - - 1,773 --------------- -------------- ------------- --------------- --------------- Net income (loss)................................. $ 12,434 $ (5,241) $ 2,537 $ (1,281) $ 8,449 =============== ============= ============= =============== ===============
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Statement of Operations For the year ended December 31, 1999 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------- --------------- --------------- Revenues: Oil and gas production revenues ............... $ 21,1 $ 29,314 $ 8,380 $ - $ 59,025 Gas processing revenues ....................... - 3,827 417 - 4,244 Rig revenues .................................. 444 - - - 444 Other ........................................ 2,811 222 24 - 3,057 --------------- -------------- ------------- --------------- --------------- 24,586 33,363 8,821 66,770 Operating costs and expenses: Lease operating and production taxes .......... 6,627 9,115 2,196 - 17,938 Depreciation, depletion, and amortization ..... 9,931 20,329 4,551 - 34,811 Proved property impairment .................... - 19,100 - - 19,100 Rig operations ................................ 624 - - - 624 General and administrative .................... 2,933 1,728 608 - 5,269 --------------- -------------- ------------- --------------- --------------- 20,115 50,272 7,355 - 77,742 --------------- -------------- ------------- --------------- --------------- Operating income (loss)........................... 4,471 (16,909) 1,466 - (10,972) F-29 Other (income) expense: Interest income ............................... (1,590) (347) (28) 1,299 (666) Amortization of deferred financing fees........ 1,484 431 - - 1,915 Interest expense............................... 28,036 9,662 416 (1,299) 36,815 --------------- -------------- ------------- --------------- --------------- 27,930 9,746 388 - 38,064 --------------- -------------- ------------- --------------- --------------- Income (loss) from operations before income tax... (23,459) (26,655) 1,078 - (49,036) Income tax expense (benefit)...................... - (13,177) 552 - (12,625) Minority interest in income of consolidated foreign subsidiary ............................ - - - (269) (269) --------------- -------------- ------------- --------------- --------------- Net income (loss) ............................... $ (23,459) $(13,478) $ 526 $ (269) $ (36,680) =============== ============== ============= =============== ===============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the year ended December 31, 2001 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------- --------------- --------------- Operating ActivitiesOperating Activities Net income (loss) ........................... $ (14,848) $ (6,512) $ 3,318 $ (1,676) $ (19,718) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority interest in income of foreign subsidiary ........................... - - - 1,676 1,676 Loss on sale of equity investment....... 845 - - - 845 Depreciation, depletion, and amortization ......................... 12,336 14,707 5,441 - 32,484 Proved property impairment ............. - 2,638 - - 2,638 Deferred income tax (benefit) expense... - (80) 1,977 - 1,897 Amortization of deferred financing fees. 1,907 361 - - 2,268 Stock-based compensation ............... (2,767) - - - (2,767) Changes in operating assets and liabilities: Accounts receivable ................ 28,804 (9,721) (6,390) - 12,693 Equipment inventory ................ (76) - - - (76) Other ............................. (281) - 175 - (106) Accounts payables and accrued expenses ......................... (12,915) (2,254) (402) - (15,571) --------------- -------------- ------------- --------------- --------------- Net cash provided (used) by operating activities ............................... 13,005 (861) 4,119 - 16,263 Investing Activities Capital expenditures, including purchases and development of properties ............ (19,126) (15,313) (22,617) - (57,056) Proceeds from sale of oil and gas properties................................ 9,677 15,882 3,379 - 28,938 Acquisition of minority interest ............ (2,679) - - - (2,679) --------------- -------------- ------------- --------------- --------------- Net cash provided (used) by investing activities ............................... (12,128) 569 (19,238) - (30,797) Financing Activities Proceeds form issuance of common stock....... 16 - - - 16 Proceeds from long-term borrowings .......... 11,700 - 18,295 - 29,995 F-30 Payments on long-term borrowings ............ (9,326) - - - (9,326) --------------- -------------- ------------- --------------- --------------- Net cash provided (used) by financing activities.................................. 2,390 - 18,295 - 20,685 --------------- -------------- ------------- --------------- --------------- 3,267 (292) 3,176 - 6,151 Effect of exchange rate changes on cash ..... - (141) (409) - (550) --------------- -------------- ------------- --------------- --------------- Increase (decrease) in cash ................. 3,267 (433) 2,767 - 5,601 Cash at beginning of year ................... 326 1,678 - - 2,004 --------------- -------------- ------------- --------------- --------------- Cash at end of year.......................... $ 3,593 $ 1,245 $ 2,767 $ - $ 7,605 =============== ============== ============= =============== ===============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the year ended December 31, 2000 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------- --------------- --------------- Operating Activities Net income (loss) ........................... $ 12,434 $ (5,241) $ 2,537 $ (1,281) $ 8,449 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority interest in income of foreign subsidiary ........................... - - - 1,281 1,281 Extraordinary gain on extinguishment of debt............................... (1,773) - - - (1,773) Gain on sale of equity investment....... (33,983) - - - (33,983) Depreciation, depletion, and amortization ......................... 12,329 18,126 5,402 - 35,857 Deferred income tax expense (bebefit)... 3,433 (153) 1,658 4,938 Amortization of deferred financing fees. 1,660 431 - - 2,091 Stock-based compensation ............... 2,767 - - - 2,767 Issuance of common stock and warrants for compensation ..................... 265 - - - 265 Changes in operating assets and liabilities: Accounts receivable ................ 8 (3,461) (3,583) - (7,036) Equipment inventory ................ (538) - - - (538) Other ............................. (184) (1,618) (37) - (1,839) Accounts payables and accrued 10,893 expenses ......................... 5,357 378 5,158 - --------------- -------------- ------------- --------------- --------------- Net cash provided by operating activities ... 1,775 8,462 11,135 - 21,372 Investing Activities Capital expenditures, including purchases and development of properties ............ (39,767) (15,649) (18,996) - (74,412) Proceeds from sale of oil and gas properties ............................... 5,542 7,393 8,222 - 21,157 Proceeds from sale of equity investment ..... 34,482 - - - 34,482 --------------- -------------- ------------- --------------- --------------- Net cash provided (used) by investing activities ............................... 257 (8,256) (10,774) - (18,773) Financing Activities Purchase of treasury stock, net ............. (78) - - - (78) Proceeds from long-term borrowings .......... 6,400 - - - 6,400 Payments on long-term borrowings ............ (9,979) - (184) - (10,163) Deferred financing fees ..................... 23 - - - 23 --------------- -------------- ------------- --------------- --------------- F-31 Net cash provided (used) by financing activities ............................... (3,634) - (184) - (3,818) --------------- -------------- ------------- --------------- --------------- (1,602) 206 177 - (1,219) Effect of exchange rate changes on cash ..... - (399) (177) - (576) --------------- -------------- ------------- --------------- --------------- Increase (decrease) in cash ................. (1,602) (193) - - (1,795) Cash at beginning of year ................... 1,928 1,871 - - 3,799 --------------- -------------- ------------- --------------- --------------- Cash at end of year.......................... $ 326 $ 1,678 $ - $ - $ 2,004 =============== ============== ============= =============== ===============
Condensed Consolidating Partent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the year ended December 31, 1999 (In thousands) Abraxas Abraxas Petroleum Restricted Reclassifi- Petroleum Corporation Subsidiary Non-Guarantor cations Corporation Inc. Parent (Canadian Subsidiary and and Company(1) Abraxas) (Grey Wolf) eliminations Subsidiaries --------------- -------------- ------------- --------------- --------------- Operating Activities Net income (loss) ........................... $ (23,459) $ (13,478) $ 526 $ (269) $ (36,680) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority interest in income of foreign subsidiary ........................... - - - 269 269 Depreciation, depletion, and amortization ......................... 9,931 20,329 4,551 - 34,811 Proved property impairment ............. - 19,100 - - 19,100 Deferred income tax (benefit) expense... - (13,595) 479 - (13,116) Amortization of deferred financing fees. 1,484 431 - - 1,915 Amortization of premium on long term debt.................................. (579) - - - (579) Issuance of common stock and warrants for compensation ..................... 53 - - - 53 Changes in operating assets and liabilities: Accounts receivable ................ 3,724 (5,201) (1,315) 94 (2,698) Equipment inventory ................ 57 - - - 57 Other ............................. 221 (177) 352 - 396 Accounts payables and accrued expenses ......................... 7,816 (8,224) 762 - 354 Other................................... (83,656) 83,750 - (94) - --------------- -------------- ------------- --------------- --------------- Net cash provided (used) by operating activities ............................... (84,408) 82,935 5,355 - 3,882 Investing Activities Capital expenditures, including purchases and development of properties ............ (19,132) (99,600) (9,976) - (128,708) Proceeds from sale of oil and gas properties and equipment inventory ....... 1,753 13,920 1,821 - 17,494 --------------- -------------- ------------- --------------- --------------- Net cash used by investing activities ....... (17,379) (85,680) (8,155) - (111,214) Financing Activities Proceeds from long-term borrowings .......... 87,006 54 1,397 - 88,457 Payments on long-term borrowings ............ (35,747) - - - (35,747) Deferred financing fees ..................... (3,586) - - - (3,586) --------------- -------------- ------------- --------------- --------------- Net cash provided by financing activities ... 47,673 54 1,397 - 49,124 --------------- -------------- ------------- --------------- --------------- (54,114) (2,691) (1,403) - (58,208) Effect of exchange rate changes on cash ..... - 392 225 - 617 --------------- -------------- ------------- --------------- --------------- F-32 Increase (decrease) in cash ................. (54,114) (2,299) (1,178) - (57,591) Cash at beginning of year ................... 56,042 4,170 1,178 - 61,390 --------------- -------------- ------------- --------------- --------------- Cash at end of year.......................... $ 1,928 $ 1,871 $ - $ - $ 3,799 =============== =============- ============= =============== ===============
15. Business Segments The Company conducts its operations through two geographic segments, the United States and Canada, and is engaged in the acquisition, development, and production of crude oil and natural gas and the processing of natural gas in each country. The Company's significant operations are located in the Texas Gulf Coast, the Permian Basin of western Texas, and Canada. Identifiable assets are those assets used in the operations of the segment. Corporate assets consist primarily of deferred financing fees and other property and equipment. The Company's revenues are derived primarily from the sale of crude oil, condensate, natural gas liquids, and natural gas to marketers and refiners and from processing fees from the custom processing of natural gas. As a general policy, collateral is not required for receivables; however, the credit of the Company's customers is regularly assessed. The Company is not aware of any significant credit risk relating to its customers and has not experienced significant credit losses associated with such receivables. In 2001, three customers accounted for approximately 41% of consolidated oil and natural gas production revenue. Three customers accounted for approximately 76% of United States revenue and five customers accounted for approximately 78% of revenue in Canada. In 2000, two customers accounted for approximately 26% of oil and natural gas production revenues. Three customers accounted for approximately 59% of United States revenue and two customers accounted for approximately 36% of revenue in Canada. In 1999, three customers accounted for approximately 58% of oil and natural gas production revenues and gas processing revenues. Business segment information about the Company's 1999 operations in different geographic areas is as follows:
U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................... $ 24,586 $ 42,184 $ 66,770 ================== ================== =================== Operating profit (loss)..................... $ 7,765 $ (15,444) $ (7,679) ================== ================== General corporate .......................... (3,293) Net interest expense and amortization of deferred financing fees ................. (38,064) ------------------- Loss before income taxes ................ $ (49,036) =================== Identifiable assets at December 31, 1999 ... $ 107,336 $ 206,474 $ 313,810 ================== ================== Corporate assets ........................... 8,474 ------------------- Total assets ............................ $ 322,284 =================== Business segment information about the Company's 2000 operations in different geographic areas is as follows: U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................... $ 32,886 $ 43,714 $ 76,600 ================== ================== =================== Operating profit............................ $ 12,446 $ 6,739 $ 19,185 ================== ================== General corporate .......................... (7,602) Net interest expense and amortization of deferred financing fees ................. (32,701) Other income (net).......................... 32,780 ------------------- Income before income taxes and extraordinary items ................... $ 11,662 =================== Identifiable assets at December 31, 2000 ... $ 132,327 $ 197,229 $ 329,556 ================== ================== F-33 Corporate assets ........................... 6,004 ------------------- Total assets ............................ $ 335,560 =================== Business segment information about the Company's 2001 operations in different geographic areas is as follows: U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................... $ 35,775 $ 41,468 $ 77,243 ================== ================== =================== Operating profit............................ $ 13,795 $ 6,665 $ 20,460 ================== ================== General corporate .......................... (1,335) Net interest expense and amortization of deferred financing fees ................. (33,713) Other expense............................... (1,052) ------------------- Loss before income taxes................. $ (15,640) =================== Identifiable assets at December 31, 2001.... $ 124,993 $ 174,063 $ 299,056 ================== ================== Corporate assets ........................... 4,657 ------------------- Total assets ............................ $ 303,713 ===================
16. Hedging Program and Derivatives On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended and interpreted. 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 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 December 31, 2001. Time Period Notional Quantities Price Fair Value --------------------------------------- ------------------------------ ------------------------------ ---------------- January, 2002 - October 31, 2002 20,000 Mcf/day of natural Fixed price swap $2.60-$2.95 $ (658,000) 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 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. F-34 For the year ended December 31, 2001, losses before tax of $12.1 million were transferred from Other Comprehensive Income (Loss) to revenue and the fair value of outstanding liabilities decreased by $25.5 million. The ineffective portion of the cash flow hedges was not material at December 31, 2001. For the year ended December 31, 2001, $566,000 of deferred net loss on derivative instruments were recorded in Other Comprehensive Income (Loss). All of the deferred net loss is expected to be reclassified to earnings during the next twelve-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 December 2001, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of $1.2 million, and a commodity price decrease of 10% would have resulted in a favorable change in fair market value of $0.9 million. In November 1996, the Company assumed swap arrangements extending through October 2001 with a counterparty involving various quantities and fixed prices. These swap arrangements provided that the Company 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, exceed certain fixed prices and for the 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 in crude oil and natural gas revenue in the period of the hedged production. These swap arrangements terminated in January 1999 and the Company was paid $750,000 by the counterparty for such termination. This amount is included in Other Revenue 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 was below the floor price, and the Company paid the counterparty when the average monthly price exceeded the ceiling price. For the year ended December 31, 1999 the Company realized a loss of $1.8 million on this agreement, which is accounted for in Crude Oil and Natural Gas Revenue. The Company has also entered into a costless collar hedge agreement with Barrett Resources Corporation ("Barrett") for the period November 1999 through October 2000. This agreement consisted of a swap for 1,000 Bbls per day of crude oil with the Company being paid $20.30 and paying NYMEX calendar month average, and an additional 1,000 Bbls of crude oil per day with a floor price of $18.00 per Bbl and a ceiling of $22.00 per Bbl. The Company realized a loss from hedges of $20.2 million for the year ended December 31, 2000, which is accounted for in Oil and Gas Production Revenue. At year end 2001 Barrett has 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 $2.60 to $2.95 for natural gas) through October 31, 2002. The Company realized a loss from hedges of $12.1 million for the year ended December 31, 2001, which is accounted for in Oil and Gas Production Revenue. 17. Comprehensive Income Comprehensive income includes net income, losses and certain items recorded directly to Stockholders' Equity and classified as Other Comprehensive Income (Loss). The following table illustrates the calculation of comprehensive income for the year ended December 31, 2001:
Accumulated Other Comprehensive Comprehensive Income Income (Loss) (Loss) ------------------- ------------------------ For the year Ended As of December 31, 2001 December 31, 2001 ------------------- ------------------------ Accumulated other comprehensive loss at December 31, 2000 (a)...... $ (4,799) F-35 Net loss........................................................ $ (19,718) ------------------- Other Comprehensive income (loss): Hedging derivatives (net of tax) - See Note 16 Cumulative effect of change in accounting principle January 1, 2001....................................................... (30,980) Reclassification adjustment for settled hedge contracts....... 12,113 Change in fair market value of outstanding hedge positions.... 18,301 ------------------- (566) Foreign currency translation adjustment......................... (8,196) ------------------- Other comprehensive income (loss).................................. (8,762) (8,762) ------------------- Comprehensive income (loss)........................................ $ ( 28,480) =================== --------------------- Accumulated other comprehensive loss at December 31, 2001.......... $ (13,561) ===================== (a) Amount at December 31, 2000 due to foreign currency translation adjustment.
18. Proved Property Impairment In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the Company's financial statements. As of December 31, 2001, the Company's net capitalized costs of oil and gas properties exceeded the present value of its estimated proved reserves by $71.3 million ($38.9 million on the U.S. properties and $32.4 million on the Canadian properties). These amounts were calculated considering 2001 year-end prices of $19.84 per barrel for oil and $2.57 per Mcf for gas as adjusted to reflect the expected realized prices for each of the full cost pools. The Company did not adjust its capitalized costs for its U.S. properties because subsequent to December 31, 2001, oil and gas prices increased such that capitalized costs for its U.S. properties did not exceed the present value of the estimated proved oil and gas reserves for its U.S. properties as determined using increased realized prices on March 22, 2002 of $24.16 per Bbl for oil and $2.89 per Mcf for gas. The Company also used the subsequent prices to evaluate its Canadian properties, and reduced the 2001 year-end write-down to an amount of $2.6 million on those properties. 19. Subsequent Event In March 2002, the Company's 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 processing 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 $21.5 million. F-36 20. Supplemental Oil and Gas Disclosures (Unaudited) The accompanying table presents information concerning the Company's crude oil and natural gas producing activities as required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." Capitalized costs relating to oil and gas producing activities are as follows:
Years Ended December 31 ------------------------------------------------------------------------------------------ 2000 2001 ---------------------------------------------- ------------------------------------------- Total U.S. Canada Total U.S. Canada --------------- -------------- ------------ ------------- ------------- -------------- (In thousands) Proved crude oil and natural gas properties ............ $ 481,802 $ 274,939 $ 206,863 $ 486,098 $ 284,182 $ 201,916 Unproved properties ......... 12,831 - 12,831 10,626 - 10,626 --------------- -------------- ------------ ------------- ------------- -------------- Total .......................... 494,633 274,939 219,694 496,724 284,182 212,542 Accumulated depreciation, depletion, and amortization, and impairment ................ (251,746) (156,148) (95,598) (280,280) (168,124) (112,156) --------------- -------------- ------------ ------------- ------------- -------------- Net capitalized costs ... $ 242,887 118,791 $ 124,096 $ 216,444 $ 116,058 $ 100,386 =============== ============== ============ ============= ============= ==============
Cost incurred in oil and gas property acquisitions, exploration and development activities are as follows: Years Ended December 31 -------------------------------------------------------------------------------------------------- 1999 2000 2001 --------------------------------------------------------------------------------------------------- Total U.S Canada Total U.S. Canada Total U.S. Canada ----------- ---------- ---------- --------- --------- ---------- ------------ ---------- --------- (In thousands) Property acquisition costs: Proved ................... $ 89,743 $ - $ 89,743 $ 7,189 $ - $ 7,189 $ - $ - $ - Unproved ................. - - - - - - - - - ----------- ---------- ---------- --------- --------- ---------- ------------ ---------- --------- $ 89,743 $ - $ 89,743 $ 7,189 $ - $ 7,189 $ - $ - $ - =========== ========== ========== ========= ========== ========== ============ ========== ======== Property development and exploration costs ........ $ 37,344 $ 18,901 $ 18,443 $64,873 $ 39,631 $ 25,242 $ 56,694 $ 18,867 $ 37,827 =========== ========== ========== ========= ========== ========== ============ ========== ========
F-37 The results of operations for oil and gas producing activities are as follows:
Years Ended December 31 -------------------------------------------------------------------------------------------------- 1999 2000 2001 --------------------------------------------------------------------------------------------------- Total U.S Canada Total U.S. Canada Total U.S. Canada ----------- ---------- ---------- --------- --------- ---------- ------------ ---------- --------- (In thousands) Revenues ................... $ 59,025 $ 21,331 $ 37,694 $ 72,973 $ 32,165 $ 40,808 $ 73,201 $ 34,934 $ 38,267 Production costs ........... (17,938) (6,627) (11,311) (18,783) (7,755) (11,028) (18,616) (9,302) (9,314) Depreciation, depletion, and amortization ......... (34,452) (9,571) (24,881) (35,497) (11,968) (23,529) (32,124) (11,976) (20,148) Proved property impairment . (19,100) - (19,100) - - - (2,638) - (2,638) General and administrative . (1,317) (733) (584) (1,722) (1,118) (604) (1,565) (1,073) (492) Income taxes (expense) benefit................... 7,455 - 7,455 (339) - (339) (2,419) - (2,419) ----------- ---------- ---------- --------- --------- ---------- ------------ ---------- --------- Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) ....... $ (6,327) $ 4,400 $(10,727) $ 16,632 $ 11,324 $ 5,308 $ 15,839 $ 12,583 $ 3,256 =========== ========== ========== ========== ========= =========== ========== ========= ========= Depletion rate per barrel of oil equivalent, before impact of impairment .... $ 6.34 $ 4.91 $ 7.13 $ 8.30 $ 6.19 $ 10.02 $ 8.81 $ 6.96 $ 10.45 =========== ========== ========== ========== ========= =========== ========== ========= =========
F-38 Estimated Quantities of Proved Oil and Gas Reserves The following table presents the Company's estimate of its net proved crude oil and natural gas reserves as of December 31, 1999, 2000, and 2001. The Company's management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by independent petroleum reserve engineers.
Total United States Canada ------------------------- ------------------------- ------------------------- Liquid Natural Liquid Natural Liquid Natural Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas ------------ ------------ ------------ ------------ ------------ ----------- Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf) (In Thousands) Proved developed and undeveloped reserves: Balance at December 31, 1998 ........... 7,695 197,478 5,751 110,239 1,944 (1) 87,239 (2) Revisions of previous estimates ...... (167) (80,592) 1,153 (45,697) (1,320) (34,895) Extensions and discoveries ........... 354 30,305 196 24,686 158 5,619 Purchase of minerals in place ........ 3,246 58,354 - - 3,246 58,354 Production ........................... (1,154) (25,698) (584) (8,190) (570) (17,508) Sale of minerals in place ............ (125) (15,542) (95) (621) (30) (14,921) ------------ -------------- ------------ ------------ ------------ ----------- Balance at December 31, 1999 (3) ....... 9,849 164,305 6,421 80,417 3,428 (1) 83,888 (2) Revisions of previous estimates ...... (216) (21,342) 54 (13,441) (270) (7,901) Extensions and discoveries ........... 791 72,498 315 57,371 476 15,127 Purchase of minerals in place ........ 254 6,822 - - 254 6,822 Production ........................... (952) (19,963) (539) (8,364) (413) (11,599) Sale of minerals in place ............ (882) (10,993) (170) (1,075) (712) (9,918) ------------ -------------- ------------ ------------ ------------ ----------- Balance at December 31, 2000............ 8,844 191,327 6,081 114,908 2,763 (1) 76,419 (2) Revisions of previous estimates ...... (627) 2,944 (688) 3,318 60 (374) Extensions and discoveries ........... 1,063 26,329 354 4,886 710 21,443 Production ........................... (732) (17,495) (416) (7,823) (316) (9,672) Sale of minerals in place ............ (1,746) (14,348) (924) (6,821) (822) (7,527) ------------ -------------- ------------ ------------ ------------ ----------- Balance at December 31, 2001............ 6,802 188,757 4,407 108,468 2,395 80,289 ============ =====================================================================
(1) Includes 269,000 and 732,000 barrels of liquid hydrocarbon reserves owned by Grey Wolf of which approximately 138,000 and 376,000 barrels are applicable to the minority interest's share of these reserves at December 31, 1999 and 2000, respectively. As of December 31, 2001 Abraxas owned 100% of Grey Wolf. (2) Includes 21,710 and 21,389 MMcf of natural gas reserves owned by Grey Wolf of which 11,140 and 10,975 MMcf are applicable to the minority interest's share of these reserves at December 31, 1999 and 2000, respectively. As of December 31, 2001 Abraxas owned 100% of Grey Wolf. (3) At year end 1999 amounts exclude the Company's proportional interest in Partnership proved reserves, accounted for by the equity method, of 2.8 Mbbls of liquid hydrocarbons and 25.8 MMcf of natural gas. F-39
Estimated Quantities of Proved Oil and Gas Reserves (continued) Total United States Canada ------------------------- ------------------------- ------------------------- Liquid Natural Liquid Natural Liquid Natural Hydrocarbons Gas Hydrocarbons Gas Hydrocarbons Gas ------------ ------------ ------------ ------------ ------------ ----------- Barrels) (Mcf) (Barrels) (Mcf) (Barrels) (Mcf) (In Thousands) Proved developed reserves: December 31, 1999....................... 7,700 128,587 4,492 53,275 3,208 75,312 =========== =========== ============ =========== ============= ============ December 31, 2000 ...................... 7,001 119,737 4,309 48,177 2,692 71,560 =========== =========== ============ =========== ============= ============ December 31, 2001....................... 5,047 111,243 2,892 40,514 2,155 70,729 =========== =========== ============ =========== ============= ============
F-40 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following disclosures concerning the standardized measure of future cash flows from proved crude oil and natural gas reserves are presented in accordance with SFAS No. 69. The standardized measure does not purport to represent the fair market value of the Company's proved crude oil and natural gas reserves. An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Under the standardized measure, future cash inflows were estimated by applying period-end prices at December 31, 2001 adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis of the properties. Operating loss carryforwards, tax credits, and permanent differences to the extent estimated to be available in the future were also considered in the future income tax calculations, thereby reducing the expected tax expense. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. F-41
Set forth below is the Standardized Measure relating to proved oil and gas reserves for: Years Ended December 31 ---------------------------------------------------------------------------------------------------- 1999 2000 2001 ----------------------------------- ----------------------------------- ----------------------------- Total U.S. Canada (1) Total U.S. Canada (1) Total U.S. Canada ----------------------------------- ----------------------------------- ----------------------------- (In thousands) Future cash inflows........ $ 577,407 $ 309,609 $ 267,798 $ 2,046,039 $ 1,274,871 $ 771,168 $ 607,375 $313,640 $ 293,735 Future production and development costs........ (181,109) (96,302) (84,807) (318,130) (254,667) (63,463) (220,613) (138,296) (82,317) Future income tax expense.. (6,319) - (6,319) (230,987) (65,421) (165,566) - - - ------------ ---------- ---------- ------------ ------------ ---------- ----------- --------- --------- Future net cash flows...... 389,979 213,307 176,672 1,496,922 954,783 542,139 386,762 175,344 211,418 Discount................... (151,528) (90,024) (61,504) (721,388) (468,663) (252,725) (177,096) (98,157) (78,939) ------------ ---------- ---------- ------------ ------------ ---------- ----------- --------- --------- Standardized Measure of discounted future net cash relating to proved reserves................. $ 238,451 $ 123,283 $ 115,168 $ 775,534 $ 486,120 $ 289,414 $ 209,666 $ 77,187 $ 132,479 ============ ========== ========= =========== ============ ========== ========== ======== ===========
At year end 1999 amounts exclude the Partnership, accounted for by the equity method, which was sold in 2000. (1) The Standardized Measure of discounted future net cash flows relating to proved reserves includes approximately $12,400 and $43,700 as of December 31, 1999 and 2000, respectively, relating to minority interest. As of December 31, 2001, Abraxas owns 100% of Grey Wolf. F-42 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure: Year Ended December 31 ---------------------------------------------------------- 1999 2000 2001 ------------------- ------------------- ------------------ (In thousands) Standardized Measure, beginning of year ................................. $ 181,581 $ 238,451 $ 775,534 Sales and transfers of oil and gas produced, net of production costs ....... (41,086) (54,190) (54,585) Net changes in prices and development and production costs from prior year .... 77,060 707,755 (613,325) Extensions, discoveries, and improved recovery, less related costs ............ 34,445 290,283 39,982 Purchases of minerals in place ............ 90,510 33,586 - Sales of minerals in place ................ (18,797) (75,391) (96,096) Revision of previous quantity estimates ... (90,030) (95,757) (2,474) Change in future income tax expense ....... (6,319) (224,668) 230,987 Other ..................................... (7,071) (68,380) (147,910) Accretion of discount ..................... 18,158 23,845 77,553 ------------------- ------------------- ------------------ Standardized Measure, end of year ....... $ 238,451 $ 775,534 $ 209,666 =================== =================== ==================
F-43 FINANCIAL STATEMENTS GREY WOLF EXPLORATION INC. December 31, 2001 F-44 AUDITORS' REPORT To the Directors of Grey Wolf Exploration Inc. We have audited the balance sheets of Grey Wolf Exploration Inc. as at December 31, 2001 and 2000 and the statements of earnings and retained earnings and of cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. With respect to the financial statements for each of the years in the two year period ended December 31, 2001, we conducted our audits in accordance with Canadian generally accepted auditing standards and auditing standards generally accepted in the United States of America. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2001 and 2000 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. On February 23, 2001, we reported separately to the shareholders of the Company on financial statements for the year ended December 31, 2000, prepared in accordance with the Canadian generally accepted accounting principles, which excluded Note 10 on differences between Canadian and United States generally accepted accounting principles. Calgary, Canada /s/ Deloitte & Touche LLP March 28, 2002 Chartered Accountants F-45 COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA - U.S. REPORTING DIFFERENCES In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) outlining changes in accounting principles that have been implemented in the financial statements. As discussed in Note 7 to the financial statements, in 2001 the Company changed its method of computing diluted earnings per share to conform to the new Canadian Institute of Chartered Accountants Handbook recommendations section 3500. In addition, as discussed in Note 6 to the financial statements, in 2000 the Company changed its method of accounting for income taxes to conform to the new Canadian Institute of Chartered Accounts Handbook recommendations section 3465. Calgary, Canada /s/ Deloitte & Touche LLP March 28, 2002 Chartered Accountants F-46 AUDITORS' REPORT To the Directors of Grey Wolf Exploration Inc. We have audited the statements of earnings and retained earnings and cash flows of Grey Wolf Exploration Inc. for the year ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these financial statements present fairly, in all material respects, the results of the Company's operations and cash flows for the year ended December 31, 1999 in accordance with Canadian generally accepted accounting principles. Calgary, Canada /s/ Ernst & Young LLP March 10, 2000 Chartered Accountants F-47
GREY WOLF EXPLORATION INC. Balance Sheets As At December 31 (thousands of dollars) 2001 2000 $ $ ------------------------------------------- ASSETS Current Cash (Note 4) 4,405 - Accounts receivable (Note 9) 9,980 9,815 ------------------------------------------- 14,385 9,815 Long-term receivable (Note 9) 10,000 - Property and equipment (Note 3) 71,879 54,782 Deferred financing fees (Note 4) 170 - ------------------------------------------- 96,434 64,597 ------------------------------------------- Liabilities Current Accounts payable and accrued liabilities (Note 9) 15,183 15,764 Long-term debt (Note 4) 36,526 11,793 Future site restoration 1,050 898 Future income taxes (Note 6) 6,359 3,297 ------------------------------------------- 59,118 31,752 ------------------------------------------- SHAREHOLDERS' EQUITY Share capital (Note 5) 27,891 27,555 Retained earnings 9,425 5,290 ------------------------------------------- 37,316 32,845 ------------------------------------------- 96,434 64,597 -------------------------------------------
See accompanying notes F-48
GREY WOLF EXPLORATION INC. Statements of Earnings and Retained Earnings Years Ended December 31 (thousands of dollars, except for share amounts) 2001 2000 1999 $ $ $ --------------------------------------------------- Revenue Petroleum and natural gas sales 30,268 26,009 15,427 Royalties, net of Alberta Royalty Tax Credit (7,615) (5,380) (2,363) --------------------------------------------------- 22,653 20,629 13,064 --------------------------------------------------- Expenses Operating 3,844 3,462 3,236 General and administrative 1,278 1,384 903 Interest and finance charges 1,827 1,126 576 Depletion, depreciation and site restoration 8,364 7,924 6,663 --------------------------------------------------- 15,313 13,896 11,378 --------------------------------------------------- Earnings before taxes 7,340 6,733 1,686 --------------------------------------------------- Provision for taxes (Note 6) Capital tax 144 61 110 Income taxes 3,061 2,732 229 --------------------------------------------------- 3,205 2,793 339 --------------------------------------------------- Net earnings 4,135 3,940 1,347 Retained earnings, beginning of year 5,290 1,912 565 Adoption of income tax accounting standard change (Note 6) - (562) - --------------------------------------------------- Retained earnings, end of year 9,425 5,290 1,912 --------------------------------------------------- Basic and diluted earnings per share (Note 7) 0.32 0.31 0.11 --------------------------------------------------- --------------------------------------------------- Weighted average number of shares Basic 12,776,407 12,660,528 12,695,313 Diluted 12,776,407 12,732,251 12,707,805 ---------------------------------------------------
See accompanying notes F-49
GREY WOLF EXPLORATION INC. Statements of Cash Flows Years Ended December 31 (thousands of dollars, except for share amounts) 2001 2000 1999 $ $ $ --------------------------------------------------- Operating Activities Net earnings 4,135 3,940 1,347 Depletion, depreciation and site restoration 8,364 7,924 6,663 Future income taxes 3,061 2,732 229 --------------------------------------------------- Cash flow from operations 15,560 14,596 8,239 Changes in non-cash working capital items (Note 8) (746) 1,936 (289) --------------------------------------------------- 14,814 16,532 7,950 --------------------------------------------------- Financing Activities Increase (decrease) in long-term debt 28,334 (273) 2,094 Increase in long-term receivable (10,000) - - Issue (repurchase) of common shares 336 3 (78) --------------------------------------------------- 18,670 (270) 2,016 --------------------------------------------------- Total cash resources provided 33,484 16,262 9,966 --------------------------------------------------- Investing Activities Property and equipment received under property swap agreement - 10,779 - Disposal of property and equipment under property swap agreement - (12,332) - --------------------------------------------------- Net cash proceeds - (1,553) - Other acquisitions (Note 9) 1,071 13 3,662 Expenditures for property and equipment 36,800 17,941 10,737 Sale of property and equipment (8,838) (342) (2,629) Site restoration 46 203 - --------------------------------------------------- 29,079 16,262 11,770 --------------------------------------------------- Increase (decrease) in cash and cash equivalents 4,405 - (1,804) Cash and cash equivalents, beginning of year - - 1,804 --------------------------------------------------- Cash and cash equivalents, end of year 4,405 - - --------------------------------------------------- Cash flow from operations per share (Note 7) Basic and diluted 1.22 1.15 0.65 --------------------------------------------------- --------------------------------------------------- Cash interest paid 1,840 1,123 614 Cash taxes paid 82 72 104 ---------------------------------------------------
See accompanying notes F-50 Grey Wolf Exploratioin, Inc. Notes to Financial Statements Years Ended December 31, 2001 and 2000 (tabular amounts in thousands of dollars, except for share amounts) 1. DESCRIPTION OF BUSINESs Grey Wolf Exploration Inc. ("Grey Wolf" or "the Company") was incorporated under the laws of the Province of Alberta on December 23, 1986. The Company's primary business is the exploration, development and production of crude oil and natural gas in western Canada. As at December 31, 2001, the Company is a wholly-owned subsidiary of Abraxas Petroleum Corporation ("Abraxas"). 2. SIGNIFICANT ACCOUNTING POLICIES The financial statements have been prepared in accordance with Canadian generally accepted accounting principles and are expressed in Canadian dollars. Differences between Canadian and U.S. GAAP are outlined in Note 10 to the financial statements. Petroleum and natural gas properties The Company follows the full cost method of accounting in accordance with the guideline issued by the Canadian Institute of Chartered Accountants ("CICA") whereby all costs associated with the exploration for and development of petroleum and natural gas reserves, whether productive or unproductive, are capitalized in a Canadian cost centre and charged to income as set out below. Such costs include acquisition, drilling, geological and geophysical costs related to exploration and development activities. Costs of acquiring and evaluating unproved properties are excluded from the depletion base until it is determined whether or not proved reserves are attributable to the properties or impairment occurs. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless crediting the proceeds against accumulated costs would result in a change in the rate of depletion of 20% or more. Depletion of petroleum and natural gas properties and depreciation of production equipment, except for gas plants and related facilities, is provided on accumulated costs using the unit-of-production method based on estimated proved petroleum and natural gas reserves, before royalties, as determined by independent engineers. For purposes of the depletion calculation, proven petroleum and natural gas reserves are converted to a common unit of measure on the basis of one barrel of oil or liquids being equal to six thousand cubic feet of natural gas. Depreciation of gas plants and related facilities is calculated on a straight-line basis over an average 18-year term. The depletion and depreciation cost base includes capitalized costs, less costs of unproved properties, plus provision for future development costs of proved undeveloped reserves. F-51 2. SIGNIFICANT ACCOUNTING POLICIES (Continued) The net carrying value of the Company's petroleum and natural gas properties is limited to an ultimate recoverable amount. This amount is the aggregate of estimated future net revenues from proved reserves and the costs of unproved properties, net of impairment allowances, less future estimated production costs, general and administration costs, financing costs, site restoration and abandonment costs, and income taxes. Future net revenues are estimated using prices and costs without escalation or discounting, and the income tax and Alberta Royalty Tax Credit legislation in effect at year end. Future abandonment and site restoration costs The estimated cost of future abandonment and site restoration is based on the current cost and the anticipated method and extent of site restoration in accordance with existing legislation and industry practice. The annual charge is provided for on a unit-of-production basis for all properties except for gas plants for which the annual charge is calculated on a straight-line basis over the estimated remaining life of the plants. Actual site restoration expenditures are charged to the accumulated liability account as incurred. Other assets Furniture, leasehold improvements, computer hardware, software and office equipment are carried at cost and are depreciated over the estimated useful life of the assets at rates varying between 20 percent and 30 percent, on a declining-balance basis. Use of estimates The amounts recorded for depletion and depreciation of property and equipment and the provision for abandonment and site restoration are based on estimates. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to uncertainty and the effect on the financial statements of changes in such estimates could be significant. Joint operations Substantially all of the Company's exploration and development activities are conducted jointly with others, and accordingly, the financial statements reflect only the Company's proportionate interest in such activities. Revenue recognition Petroleum and natural gas sales are recognized when the commodities are delivered to purchasers. F-52 2. SIGNIFICANT ACCOUNTING POLICIES (Continued) Future income taxes The Company has adopted, on a retroactive basis without restatement of the 1999 financial statements, the CICA new accounting recommendation, "Income Taxes". Under this standard, future income tax assets and liabilities are measured based upon temporary differences between the carrying values of assets and liabilities and their tax basis. Income tax expense (recovery) is computed based on the change during the year in the future tax assets and liabilities. Effects of changes in tax laws and tax rates are recognized when substantially enacted. Financial instruments Financial instruments of the Company consist of accounts receivable, long-term receivable, accounts payable and accrued liabilities, and long-term debt. As at December 31, 2001 and 2000, there were no significant differences between the carrying amounts of these financial instruments reported on the balance sheets and their estimated fair values. The Company also from time to time employs financial instruments to manage its exposure to commodity prices. These instruments are not used for speculative trading purposes. Gains and losses on commodity price hedges are included in revenues upon the sale of the related production provided there is reasonable assurance that the hedge is and will continue to be effective. Stock options The Company has a stock option plan as described in Note 5. No compensation expense is recognized when the stock options are issued. Consideration received on exercise of stock options is credited to share capital. Earnings per share Basic earnings per share is calculated using the weighted average number of common shares outstanding during the year. Diluted earnings per share is calculated on the basis of the weighted average number of shares outstanding during the year plus the additional common shares that would have been outstanding if potentially dilutive common shares had been issued using the "treasury stock" method. Effective January 1, 2001, the Company retroactively adopted, with restatement of prior periods, the recommendations of new CICA Handbook Section 3500 for calculating earning per share. Under the revised standard, the treasury stock method is used for determining the dilutive effect of options issued. Prior to the adoption of the new recommendations, diluted per share amounts were determined using the imputed earnings method. F-53 3. PROPERTY AND EQUIPMENT
2001 --------------------------------------------------------- Accumulated Depletion and Net Book Cost Depreciation Value $ $ $ --------------------------------------------------------- Petroleum and natural gas properties 89,516 (25,901) 63,615 Gas plants and related production facilities 11,010 (2,845) 8,165 Other assets 597 (498) 99 --------------------------------------------------------- Net property and equipment 101,123 (29,244) 71,879 --------------------------------------------------------- 2000 --------------------------------------------------------- Accumulated Depletion and Net Book Cost Depreciation Value $ $ $ --------------------------------------------------------- Petroleum and natural gas properties 69,543 (19,384) 50,159 Gas plants and related production facilities 5,786 (1,326) 4,460 Other assets 531 (368) 163 --------------------------------------------------------- Net property and equipment 75,860 (21,078) 54,782 ---------------------------------------------------------
Undeveloped property costs of $6,065,907 at December 31, 2001 (2000 - $6,441,705, 1999 - $7,365,579) have been excluded from the depletion base. F-54 4. LONG-TERM DEBT At December 31, 2001, the Company had a credit facility with Mirant Canada Energy Capital Ltd., (the "Mirant Facility") with a maximum available limit of $150,000,000. At December 31, 2001, $40,127,000 was drawn down against this facility. Of the $40,127,000 drawn, $10,000,000 was advanced to Canaxas (Note 9). Under the Mirant Facility, the Company is required to pay an amount equal to monthly net cash flow from operations less interest payments, general and administrative expenses and approved capital expenditures. It is anticipated the Company will be a net borrower due to a number of planned capital projects over the next several years. Accordingly, the outstanding balance has been classified as long-term on the balance sheet. The facility matures in December 2007. Under the facility, loan advances bear interest at 9.5%, plus a 5% overriding royalty which will decrease to 2 1/2% when certain conditions are met. The overriding royalty granted to Mirant was treated as a disposition of petroleum and natural gas properties, with a corresponding deferred financing charge recorded of $3,600,000 based on the fair value at the date of disposition. This deferred charge was netted against the outstanding loan balance and will be amortized over a 6-year period ended in 2007. Loan advances are supported by a first charge demand debenture in the amount of $200,000,000 covering all the assets of the Company. The Mirant credit facility was used to extinguish the previous revolving term credit facility. As at December 31, 2001, all of the previous revolving term credit facility had been repaid except for a bankers acceptance for $5,000,000. As at December 31, 2001, equivalent cash had been placed in trust to cover the $5,000,000 repayment, and accordingly was netted against the loan for financial statement purposes. The remaining $5,000,000 was repaid in January 2002. At December 31, 2000, the Company had a revolving term credit facility with a Canadian chartered bank with a maximum limit of $20,000,000. At December 31, 2000, $11,792,690 was drawn down against this facility. Under the facility, loan advances bore interest at bank prime plus 1/8%, or if bankers acceptances were utilized, the then current bankers acceptances rate plus 1 1/8%. Loan advances were supported by a first floating charge demand debenture in the amount of $25,000,000 covering all the assets of the Company. During May 2001, the maximum limit under the revolving term credit facility was increased to $27,000,000 and remained at this level replaced by the Mirant Facility in December 2001. F-55 5. SHARE CAPITAL Authorized Unlimited number of common shares without nominal or par value. Issued
Number of Amount Shares $ -------------------------------------- Balance, December 31, 1998 12,704,341 27,630 Issuer bid (44,600) (78) -------------------------------------- Balance, December 31, 1999 12,659,741 27,552 Exercise of stock options 1,800 3 -------------------------------------- Balance, December 31, 2000 12,661,541 27,555 Exercise of stock options 179,786 336 -------------------------------------- Balance, December 31, 2001 12,841,327 27,891 --------------------------------------
On May 20, 1999, the Company's shareholders approved the consolidation of the share capital of the Company on the basis of one common share for each ten common shares outstanding. All common share and per share amounts have been reflected on a post consolidation basis. Stock options A maximum of 1,270,000 options to purchase common shares have been authorized for issuance under the Company's stock option plan. The options were exercisable on a cumulative basis at 25% per year commencing one year after grant date and expire five years from the date of grant. During the year ended December 31, 2001, all options outstanding in the Company were cancelled and new options were issued by Abraxas.
Number Weighted Average of Options Option Price ---------------------------------------------- Balance, December 31, 1998 897,816 3.20 Issued 328,470 1.91 Cancelled (192,571) 2.83 ---------------------------------------------- Balance, December 31, 1999 1,033,715 2.84 Issued 398,376 1.60 Exercised (1,800) 1.60 Cancelled (420,262) 2.53 ---------------------------------------------- F-56 Balance, December 31, 2000 1,010,029 2.30 ---------------------------------------------- Cancelled 1,010,029 2.30 ---------------------------------------------- Balance December 31, 2001 - - ----------------------------------------------
6. PROVISION FOR TAXES The Company accounts for future income taxes using the liability method. Future income tax assets and liabilities are measured based upon temporary differences between the carrying values of assets and liabilities and their tax bases. Income tax expense (recovery) is computed based on the change during the year in the future tax assets and liabilities. Future income tax liabilities or assets are calculated using tax rates anticipated to apply in the periods that the temporary differences are expected to reverse. Effects of changes in tax laws and tax rates are recognized when substantially enacted. The provision for taxes recorded on the statements of earnings and retained earnings differs from the tax calculated by applying the combined statutory Canadian corporate and provincial income tax rate as follows:
2001 2000 1999 $ $ $ -------------------------------------------------------- Calculated income tax expense at 42.62%, (2000 and 1999 - 44.62%) 3,128 3,004 752 Increase (decrease) in tax resulting from: Non-deductible crown royalties and other charges 2,950 2,254 2,147 Resource allowance and related items (2,757) (2,066) (1,174) Alberta Royalty Tax Credit (177) (231) (1,392) Non-deductible depletion and depreciation - - 43 Benefit of losses not previously recognized - - (147) Large Corporation Tax 144 61 110 Tax rate adjustment (151) - - Other 68 (229) - -------------------------------------------------------- Provision for taxes 3,205 2,793 339 --------------------------------------------------------
The major components of future income tax liability at December 31, 2001 and 2000 are related to the following accounts:
2001 2000 $ $ ------------------- ------------------ Property and equipment 7,672 4,767 Future site restoration (447) (401) Share issue costs (117) (94) Non-capital losses carried forward - (557) Attributed royalty income carried forward (511) (144) Resource allowance (310) (274) Deferred financing costs 72 - ------------------- ------------------ Balance, December 31 6,359 3,297 ------------------- ------------------
F-57 6. PROVISION FOR TAXES (Continued) Upon adoption of the new accounting recommendation of the CICA, the Company recorded a future income tax liability of $562,000 and decreased the Company's retained earnings by $562,000. Had the new method not been adopted, 2000 net earnings would have been increased by $88,000. As at December 31, 2001 and 2000, the Company has exploration and development costs, undepreciated capital costs, non-capital losses and unamortized share issue costs available for deduction against future taxable income in the following approximate amounts:
2001 2000 $ $ ----------------------------------- Canadian oil and gas property expense 14,816 21,158 Canadian development expense 18,526 9,838 Canadian exploration expense 11,245 5,735 Undepreciated capital cost 9,290 7,097 Non-capital losses - 1,249 Unamortized share issue costs 276 210 ----------------------------------- 54,153 45,287 -----------------------------------
The Company's non-capital losses are available to be carried forward to offset taxable income in future years and expire between 2002 and 2004. 7. EARNINGS PER SHARE The treasury method of calculating earnings per share was adopted retroactively effective January 1, 2001, with restatement of prior periods. If the imputed earnings method was utilized for 2000, diluted net earnings per share would be $0.31 per share (1999 - $0.11) and diluted cash flow from operations per share would be $1.11 (1999 - $0.62). There is no impact on 2001 diluted per share figures as a result of adopting the new treasury method. 8. SUPPLEMENTARY CASH FLOW INFORMATION
2001 2000 1999 $ $ $ -------------------------------------------------------- Accounts receivable (165) (5,712) (1,390) Accounts payable and accrued liabilities (581) 7,648 1,101 -------------------------------------------------------- Changes in non-cash working capital items (746) 1,936 (289) --------------------------------------------------------
F-58 9. RELATED PARTY TRANSACTIONS The Company manages the assets and operations of Canadian Abraxas Petroleum Limited ("Canaxas") pursuant to a Management Agreement dated November 12, 1996. Canaxas is a wholly-owned subsidiary of Abraxas. As at December 31, 2001, Abraxas owned 97.3% (2000 - 46.0%) of the common shares of the Company and Canaxas owned 2.7% (2000 - 2.7%) of the common shares of the Company. The aggregate common costs of operations and administration of the Canaxas and Grey Wolf assets are shared on a pro-rata basis, based on revenue. Amounts due to and from these related parties with respect to the Management Agreement are $3,741,000 at December 31, 2001 (2000 - $3,823,000). Abraxas also charged the Company a corporate service charge of $849,000 in 2001 (2000 and 1999 - $Nil) of which $589,000 was charged out to Canaxas. The amounts are non-interest earning, are not collateralized and are due on demand. In addition, at December 31, 2001, the Company had a long-term receivable from Canaxas in the amount of $10,000,000 (Note 4) (2000 - $Nil). The balance bears interest at 9.65% and has no fixed terms of repayment.
2001 2000 $ $ ---------------------------------- Receivable from Canaxas 4,330 3,823 Long-term receivable from Canaxas 10,000 - Payable to Abraxas 849 -
In July 1999, the Company purchased undeveloped property from a wholly-owed subsidiary of Canaxas for a total cost of $3,421,000. As a result of this acquisition, the Company was committed to spend $6,000,000 prior to June 30, 2002 pursuant to the terms of a farm-in agreement between the Company and the wholly-owned subsidiary of Canaxas. 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES Reconciliation of Financial Statements to United States Generally Accepted Accounting Principles The financial statements of the Company have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"), which in most respects, conform to accounting principles generally accepted in the United States of America ("U.S. GAAP"). Differences from U.S. GAAP having a significant effect on the Company's balance sheets and statements of earnings and retained earnings and of cash flows are described and quantified below for the years indicated: F-59 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) (a) Tnder U.S. GAAP, interest costs associated with certain capital expenditures are required to be capitalized as part of the historical cost of the oil and gas assets. Under Canadian GAAP, the calculation of interest costs eligible for capitalization differs from the calculation under U.S. GAAP in certain respects and is optional at the discretion of the entity. Accordingly, no amounts have been capitalized with respect to the Canadian GAAP financial statements. The impact of recording capitalized interest under U.S. GAAP would be to increase the carrying value of property and equipment by $119,000 in 2001 and $69,000 in 2000 with a corresponding decrease in interest expense in the respective periods. (b) Under U.S. GAAP, deferred taxes are recorded based upon the liability method. When a business combination occurs, deferred taxes are recognized for the tax effect of timing differences, with a corresponding increase in property and equipment. Under Canadian GAAP, prior to the adoption of the new CICA accounting recommendation, "Future Income Taxes" effective January 1, 2000, the Company followed the deferral method of accounting for income taxes. The impact of the difference in 1999 is an additional deferred tax expense under U.S. GAAP of $480,000. Upon adoption of the new recommendation for Canadian GAAP, companies were permitted to record the impact of differences in accounting and tax bases related to prior business combinations to retained earnings as a one-time transition adjustment. Accordingly, property and equipment is higher under U.S. GAAP by $682,000 for 2001 and 2000 before the impact of depletion. The impact of the additional depletion expense related to the increased property and equipment for U.S. GAAP purposes is to decrease net income by $62,000 in 2001, $88,000 in 2000, and $77,000 in 1999. The cumulative impact of the depletion expense relating to years prior to 1999 is $78,000. (c) In September 2001, Abraxas acquired the remaining non-controlling interest of the Company. Consideration was comprised of 0.6 common shares of Abraxas, in exchange for each common share of the Company. Under U.S. GAAP, the costs assigned to assets and liabilities by the acquiring company under a business combination are considered to constitute a new basis of accounting. Accordingly, the historical carrying values of assets and liabilities of the subsidiary are comprehensively revalued based on the purchase price assigned for consolidation purposes at the time it becomes wholly owned ("push down accounting"). Under Canadian GAAP, comprehensive revaluation of assets and liabilities in the financial statements of a subsidiary based on a purchase transaction involving acquisition of all of the equity interests is permitted, but not required. Had the consolidation entries of Abraxas related to the acquisition been applied in the Company's financial statements using "push down accounting", property and equipment and future income tax liability would be reduced by $4,074,000 and $1,736,000, respectively, accounts receivable would be increased and interest and finance charges decreased by $984,000 (relating to certain costs of the transaction paid by the Company), with the remaining amount of $2,338,000 recorded as a revaluation adjustment within shareholders'equity. F-60 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) (d) Prior to 2001, Canadian GAAP required the use of the imputed earnings method for purposes of the calculation of fully diluted earnings per share. For fiscal periods beginning on or after January 1, 2001, retroactive application of the treasury stock method with restatement of prior periods is required, which is substantially the same as No. SFAS 128 under U.S. GAAP. Accordingly, no adjustments are required to conform the diluted earnings per share figures to U.S. GAAP, except for the net income effect of the above-noted Canadian - U.S. GAAP differences identified. (Tabular amounts are in thousands of Canadian dollars, except per share amounts) STATEMENTS OF EARNINGS The application of U.S. GAAP would have the following effect on the Statements of Earnings:
Years Ended December 31, ------------------------------------------------- 2001 2000 1999 $ $ $ --------------- ----------------- --------------- Net earnings, as reported 4,135 3,940 1,347 Capitalized interest (a) 119 69 - Depreciation, depletion and amortization (b) (62) (88) (77) Deferred income tax expense benefit (b) - - (480) Interest and finance charges (c) 984 - - --------------- ----------------- --------------- Net earnings, U.S. GAAP 5,176 3,921 790 --------------- ----------------- --------------- Basic earnings per share, as reported 0.32 0.31 0.11 Effect of increase (decrease) in net earnings under U.S. GAAP (d) 0.09 - (0.05) --------------- ----------------- --------------- Basic earnings per share, U.S. GAAP 0.41 0.31 0.06 --------------- ----------------- --------------- Diluted earnings per share, as reported 0.32 0.31 0.11 Effect of increase (decrease) in net earnings under U.S. GAAP (d) 0.09 - (0.05) --------------- ----------------- --------------- Diluted earnings per share, U.S. GAAP 0.41 0.31 0.06 --------------- ----------------- ---------------
F-61 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) BALANCE SHEETS The application of U.S. GAAP would have the following effect on the Balance Sheets:
As At December 31, 2001 As At December 31, 2000 ------------------------------------------ ------------------------------------------- Cumulative As Increase U.S. As Increase U.S. Reported (Decrease) GAAP Reported (Decrease) GAAP -------------- --------------- ----------- ------------- ---------------- ------------ ASSETS Accounts receivable (c) 9,980 984 10,964 9,815 - 9,815 Property and equipment (a) (b) (c) 71,879 (3,509) 68,370 54,782 510 55,292 LIABILITIES Deferred income taxes (c) 6,359 (1,736) 4,623 3,297 - 3,297 SHAREHOLDERS' EQUITY Revaluation adjustment (c) - (2,338) (2,338) - - - Retained earnings (a) (b) 9,425 1,549 10,974 5,290 510 5,800
F-62 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) STATEMENTS OF CASH FLOWS The application of U.S. GAAP would have the following effect on the Statements of Cash Flows:
Years Ended December 31, -------------------------------------------- 2001 2000 1999 $ $ $ ------------- --------------- -------------- OPERATING ACTIVITIES Cash flow from operating activities, as reported 14,814 16,532 7,950 Increase (decrease) in: Net earnings (loss) 1,041 (19) (557) Depletion, depreciation and amortization (b) 62 88 77 Deferred income taxes (b) - - 480 Changes in non-cash working capital items (c) (984) - - ------------- --------------- -------------- Cash flow from operating activities, U.S. GAAP 14,933 16,601 7,950 ------------- --------------- -------------- INVESTING ACTIVITIES Net cash (used) provided by investing activities, as reported (29,079) (16,262) (11,770) Increase in capital expenditures (a) (119) (69) - ------------- --------------- -------------- Net cash (used) provided by investing activities, U.S. GAAP (29,198) (16,331) (11,770) ------------- --------------- --------------
Statements of Cash Flows The investing activities portion of the statement of cash flows for 2000 prepared under Canadian GAAP discloses the aggregate costs related to a property swap arrangement, with adjustments to arrive at the cash component of the transaction. Under U.S. GAAP only the net cash amount would be presented on the statement of cash flows. F-63 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) Under Canadian GAAP, corporations are permitted to present a sub-total prior to changes in non-cash working capital within operating activities. This information is perceived to be useful information for various users of the financial statements and is commonly presented by Canadian public corporations. Under U.S. GAAP, this sub-total is not permitted to be shown and would be removed in the statements of cash flows for all periods presented. In addition, cash flow from operations per share figures would not be presented under U.S. GAAP. Recent Developments in U.S. Accounting The Financial Accounting Standards Board recently issued Statement No. 141, "Business Combinations" (FAS No. 141) and Statement No. 142 "Goodwill and Other Intangible Assets" (FAS No. 142). FAS No. 141 requires the purchase method of accounting to be used for all business combinations after July 1, 2001. FAS No. 142 requires that goodwill and intangible assets with an indefinite useful life no longer be amortized, but instead tested for impairment at least annually. Enterprises are required to adopt FAS No. 142 for fiscal years beginning after December 15, 2001. FAS No. 141 has been applied with respect to the acquisition by Abraxas of the remaining non-controlling interest in Grey Wolf. The Company currently has no goodwill or other intangible assets that will be impacted by the adoption of FAS No. 142. Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS No. 143) was released by the Financial Accounting Standards Board in June 2001. FAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets. The initial market of the asset retirement obligation is to be at fair value. The asset retirement cost equal to the fair value of the retirement obligation is to be capitalized as part of the cost of the related long-lived asset and amortized to expense over the useful life of the asset. Enterprises are required to adopt FAS No. 143 for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact that adoption of this standard would have on its financial position and results of operations. F-64 10. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) The Financial Accounting Standards Board also recently issued Statement No. 144, "Accounting for the Impairment of Disposal of Long-Lived Assets" (FAS No. 144). FAS No. 144 will replace previous Untied States generally accepted accounting principles regarding accounting for impairment of long-lived assets and accounting and reporting for discontinued operations. FAS No. 144 retains the fundamental provisions of the prior standard for recognizing and measuring impairment losses on long-lived assets. FAS No. 144 retains the basic provisions of the prior standard for presentation of discontinued operations in the income statement, but broadens that presentation to include a component of an entity rather than a segment of a business. Enterprises are required to adopt FAS No. 144 for fiscal years beginning after December 15, 2001. The Company has adopted the accounting standard effective January 1, 2002 which is not expected to have a significant impact on the Company's financial position and results of operations. 11. SUBSEQUENT EVENT Subsequent to December 31, 2001, the Company entered into an agreement to dispose of its non-operated interest in the Quirk Creek gas processing facilities and related petroleum and natural gas rights, for proceeds of $3,450,000. The agreement is expected to close during the second quarter of 2002. F-65 EX-3.(II) 2 amendedarticles.txt Exhibit 3.6 AMENDED AND RESTATED BYLAWS OF ABRAXAS PETROLEUM CORPORATION, a Nevada Corporation (January 18,2002) ARTICLE I OFFICES Section 1. Principal Office and Registered Agent. The principal office of the Corporation in the state of Nevada shall be at One East First Street, Reno, Washoe County, Nevada 89501. The name and address of the registered agent is the Corporation Trust Company of Nevada, One East First Street, Reno, Washoe County, Nevada 89501. Section 2. Other Offices. The Corporation may also have offices at such other places both within and without the State of Nevada as the Board of Directors may from time to time determine or the business of the Corporation may require. ARTICLE II STOCKHOLDERS Section 1. Place of Meeting. All meetings of the stockholders shall be held at the principal office of the Corporation, or at such other place within or without the State of Nevada as shall be specified or fixed in the notices or waivers of notice thereof. Section 2. Quorum, Adjournment of Meeting. Unless otherwise required by law or provided in the Articles of Incorporation or these Bylaws, the holders of a majority of the stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at any meeting of stockholders for the transaction of business and the act of a majority of such stock so represented at any meeting of stockholders at which a quorum is present shall constitute the act of the stockholders. The stockholders present at a duly organized meeting may continue to transact business until adjournment, notwithstanding the withdrawal of enough stockholders to leave less than a quorum. Notwithstanding the other provisions of the Articles of Incorporation or these Bylaws, the chairman of the meeting or the holders of a majority of the issued and outstanding stock, present in person or represented by proxy, at any meeting of stockholders, whether or not a quorum is present, shall have the power to adjourn such meeting from time to time, without any notice other than announcement at the meeting of the time and place of the holding of the adjourned meeting. If the adjournment is for more than thirty (30) days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at such meeting. At such adjourned meeting at which a quorum shall be present or represented any business may be transacted which might have been transacted at the meeting as originally called. Section 3. Annual Meetings. An annual meeting of the stockholders, for the election of directors to succeed those whose terms expire and for the transaction of such other business as may properly come before the meeting, shall be held at such place, within or without the State of Nevada, on such date, and at such time as the Board of Directors shall fix and set forth in the notice of the meeting. Section 4. Special Meetings. Special meetings of stockholders of the Corporation may be called only by the Chairman of the Board, the President or the Board of Directors pursuant to a resolution approved by a majority of the entire Board of Directors of the Corporation (as determined in accordance with the Bylaws of the Corporation). Notwithstanding anything contained in the Articles of Incorporation or Bylaws of the Corporation to the contrary, the affirmative vote of the holders of at least 80% of the voting power of the then outstanding shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, shall be required to amend or repeal this Section 4 or adopt any provision inconsistent with any provision of this Section 4. Section 5. Record Date. For the purpose of determining stockholders entitled to notice of or to vote at any meeting of stockholders, or any adjournment thereof, or entitled to express consent to corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors of the Corporation may fix in advance, a date as the record date for any such determination of stockholders, which date shall not be more than sixty (60) days nor less than ten (10) days before the date of such meeting, nor more than sixty (60) days prior to any other action. If the Board of Directors does not fix a record date for any meeting of the stockholders, the record date for determining stockholders entitled to notice of or to vote at such meeting shall be at the close of business on the day next preceding the day on which notice is given, or, if in accordance with Article VIII, Section 3 of these Bylaws, notice is waived, at the close of business on the day next preceding the day on which the meeting is held. If, in 2 accordance with Section 12 of this Article II, corporate action without a meeting of stockholders is to be taken, the record date for determining stockholders entitled to express consent to such corporate action in writing, when no prior action by the Board of Directors is necessary, shall be the day on which the first written consent is expressed. The record date for determining stockholders for any other purpose shall be at the close of business on the date on which the Board of Directors adopts the resolution relating thereto. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting. Section 6. Notice of Meetings. Written notice signed by the President, Vice President, Secretary, or Assistant Secretary, or other persons as the President or Board of Directors may designate, of the place, date and hour of all meetings, and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be given by or at the direction of the Chairman of the Board or the President, the Secretary or the other person(s) calling the meeting to each stockholder entitled to vote thereat not less than ten (10) nor more than sixty (60) days before the date of the meeting. Such notice may be delivered either personally or by mail. If mailed, notice is given when deposited in the United States mail, postage prepaid, directed to the stockholder at his address as it appears on the records of the Corporation. Section 7. Stock List. A complete list of stockholders entitled to vote at any meeting of stockholders, arranged in alphabetical order for each class of stock and showing the address of each such stockholder and the number of shares registered in the name of such stockholder, shall be open to the examination of any stockholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least ten (10) days prior to the meeting, either at the offices of the Corporation in San Antonio, Texas or a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or if not so specified, at the place where the meeting is to be held. The stock list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any stockholder who is present. Section 8. Proxies. Each stockholder entitled to vote at a meeting of stockholders or to express consent or dissent to a corporate action in writing without a meeting may authorize another person or persons to act for him by proxy. Proxies for use at any meeting of stockholders shall be in writing and filed with the Secretary, or such other officer as the Board of Directors may from time to time determine by resolution, before or at the time of the meeting. All proxies shall be received and taken charge of and all ballots shall be received and canvassed by the secretary of the meeting who shall decide all questions touching upon the qualification of voters, the validity of the proxies and the acceptance or rejection of votes, unless an inspector or inspectors shall have been appointed by the chairman of the meeting, in which event such inspector or inspectors shall decide all such questions. 3 No proxy shall be valid after six (6) months from its date, unless the proxy provides for a longer period, which in no event may exceed seven (7) years. Each proxy shall be revocable unless expressly provided therein to be irrevocable and coupled with an interest sufficient in law to support an irrevocable power. Should a proxy designate two or more persons to act as proxies, unless such instrument shall provide the contrary, a majority of such persons present at any meeting at which their powers thereunder are to be exercised shall have and may exercise all the powers of voting or giving consents thereby conferred, or if only one be present, then such powers may be exercised by that one; or, if an even number attend and a majority do not agree on any particular issue, each proxy so attending shall be entitled to exercise such powers in respect of the same portion of the shares as he is of the proxies representing such shares. Section 9. Voting, Elections; Inspections. Unless otherwise required by law or provided in the Articles of Incorporation, each stockholder shall have one vote for each share of stock entitled to vote which is registered in his name on the record date for the meeting. Shares registered in the name of another corporation, domestic or foreign, may be voted by such officer, agent or proxy as the bylaw (or comparable instrument) of such corporation may prescribe, or in the absence of such provision, as the Board of Directors (or comparable body) of such corporation may determine. Shares registered in the name of a deceased person may be voted by his executor or administrator, either in person or by proxy. All voting, except as required by the Articles of Incorporation or where otherwise required by law, may be by a voice vote; provided, however, that upon demand therefor by stockholders holding a majority of the issued and outstanding stock present in person or by proxy at any meeting a stock vote shall be taken. Every stock vote shall be taken by written ballots, each of which shall state the name of the stockholder or proxy voting and such other information as may be required under the procedure established for the meeting. All elections of directors shall be by ballot, unless otherwise provided in the Articles of Incorporation. At any meeting at which a vote is taken by ballots, the chairman of the meeting may appoint one or more inspectors, each of whom shall subscribe an oath or affirmation to execute faithfully the duties of inspector at such meeting with strict impartiality and according to the best of his ability. Such inspector shall receive the ballots, count the votes and make and sign a certificate of the result thereof. The chairman of the meeting may appoint any person to serve as inspector, except no candidate for the office of director shall be appointed as an inspector. Unless otherwise provided in the Articles of Incorporation, cumulative voting for the election of directors shall be prohibited. Section 10. Conduct of Meetings. The meetings of the stockholders shall be presided over by the Chairman of the Board, or if he is not present, by the President, or if neither the Chairman of the Board nor the President is present, by a chairman elected at the meeting. The Secretary of the Corporation, if 4 present, shall act as secretary of such meetings, or if he is not present, an Assistant Secretary shall so act; if neither the Secretary nor an Assistant Secretary is present, then a secretary shall be appointed by the chairman of the meeting. The chairman of any meeting of stockholders shall determine the order of business and the procedure at the meeting, including such regulation of the manner of voting and the conduct of discussion as seem to him in order. Section 11. Treasury Stock. The Corporation shall not vote, directly or indirectly, shares of its own stock owned by it and such shares shall not be counted for quorum purposes. Section 12. Action Without Meeting. Any action required or permitted to be taken by the stockholders of the Corporation must be effected at an annual or special meeting of stockholders of the Corporation and may not be effected by any consent in writing by such stockholders. Notwithstanding anything contained in the Articles of Incorporation or Bylaws of the Corporation to the contrary, the affirmative vote of the holders of at least 80% of the voting power of the then outstanding shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, shall be required to amend or repeal this Section 12 or adopt any provision inconsistent with any provision of this Section 12. Section 13. Notice of Stockholder Business and Nominations. (A) Annual Meetings of Stockholders. (1) Nominations of persons for election to the Board of Directors of the Corporation and the proposal of business to be considered by the stockholders may be made at an annual meeting of stockholders (a) pursuant to the Corporation's notice of meeting, (b) by or at the direction of the Board of Directors or (c) by any stockholder of the Corporation who was a stockholder of record at the time of giving of notice provided for in this Section 13, who is entitled to vote at the meeting and who complies with the notice procedures set forth in this Section 13. (2) For nominations or other business to be properly brought before an annual meeting by a stockholder pursuant to clause (c) of paragraph (A)(1) of this Section 13, the stockholder must have given timely notice thereof in writing to the Secretary of the Corporation and such other business must otherwise be a proper matter for stockholder action. To be timely, a stockholder's notice shall be delivered to the Secretary at the principal executive offices of the Corporation not later than the close of business on the 60th day nor earlier than the close of business on the 90th day prior to the first anniversary of the preceding year's annual meeting; provided, however, that in the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, notice by the stockholder to be timely must be so delivered not earlier than the close of business on the 90th day prior to such annual meeting and not later than the close of business on the later of the 60th day prior to such annual meeting or the 10th day following the day on which public announcement of the date of such meeting is first made by the Corporation. In no event shall the public announcement of an adjournment of an annual meeting commence a new time period for the giving of a stockholder's notice as described above. Such stockholder's notice shall set forth (a) as to each person whom the stockholder proposes to 5 nominate for election or re-election as a director all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors in an election contest, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and Rule 14a-11 thereunder (including such person's written consent to being named in the proxy statement as a nominee and to serving as a director if elected); (b) as to any other business that the stockholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest in such business of such stockholder and the beneficial owner, if any, on whose behalf the proposal is made; and (c) as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (i) the name and address of such stockholder, as they appear on the Corporation's books, and of such beneficial owner and (ii) the class and number of shares of the Corporation which are owned beneficially and of record by such stockholder and such beneficial owner. (3) Notwithstanding anything in the second sentence of paragraph (A)(2) of this Section 13 to the contrary, in the event that the number of directors to be elected to the Board of Directors of the Corporation is increased and there is no public announcement by the Corporation naming all of the nominees for director or specifying the size of the increased Board of Directors at least 70 days prior to the first anniversary of the preceding year's annual meeting, a stockholder's notice required by this Section 13 shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to the Secretary at the principal executive offices of the Corporation not later than the close of business on the 10th day following the day on which such public announcement is first made by the Corporation. (B) Special Meetings of Stockholders. Only such business shall be conducted at a special meeting of stockholders as shall have been brought before the meeting pursuant to the Corporation's notice of meeting. Nominations of persons for election to the Board of Directors may be made at a special meeting of stockholders at which directors are to be elected pursuant to the Corporation's notice of meeting (a) by or at the direction of the Board of Directors or (b) provided that the Board of Directors has determined that directors shall be elected at such meeting, by any stockholder of the Corporation who is a stockholder of record at the time of giving of notice provided for in this Section 13, who shall be entitled to vote at the meeting and who complies with the notice procedures set forth in this Section 13. In the event the Corporation calls a special meeting of stockholders for the purpose of electing one or more directors to the Board of Directors, any such stockholder may nominate a person or persons (as the case may be), for election to such position(s) as specified in the Corporation's notice of meeting, if the stockholder's notice required by paragraph (A)(2) of this Section 13 shall be delivered to the Secretary at the principal executive offices of the Corporation not earlier than the close of business on the 90th day prior to such special meeting and not later than the close of business on the later of the 60th day prior to such special meeting or the 10th day following the day on which public announcement is first made of the date of the special meeting and of the 6 nominees proposed by the Board of Directors to be elected at such meeting. In no event shall the public announcement of an adjournment of a special meeting commence a new time period for the giving of a stockholder's notice as described above. (C) General. (1) Only such persons who are nominated in accordance with the procedures set forth in this Section 13 shall be eligible to serve as directors and only such business shall be conducted at a meeting of stockholders as shall have been brought before the meeting in accordance with the procedures set forth in this Section 13. Except as otherwise provided by law, the Articles of Incorporation or these Bylaws, the Chairman of the meeting shall have the power and duty to determine whether a nomination or any business proposed to be brought before the meeting was made or proposed, as the case may be, in accordance with the procedures set forth in this Section 13 and, if any proposed nomination or business is not in compliance with this Section 13, to declare that such defective proposal or nomination shall be disregarded. (2) For purposes of this Section 13, "public announcement" shall mean disclosure in a press release reported by the Dow Jones News Service, Associated Press or comparable national news service or in a document publicly filed by the Corporation with the Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act. (3) Notwithstanding the foregoing provisions of this Section 13, a stockholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 13. Nothing in this Section 13 shall be deemed to affect any rights (i) of stockholders to request inclusion of proposals in the Corporation's proxy statement pursuant to Rule 14a-8 under the Exchange Act or (ii) of the holders of any series of Preferred Stock to elect directors under specified circumstances. (D) Amendment. Notwithstanding any other provisions of the Articles of Incorporation or the Bylaws of the Corporation (and notwithstanding the fact that a lesser percentage may be specified by law, the Articles of incorporation or the Bylaws of the Corporation), the affirmative vote of the holders of at least 80% of the voting power of the then outstanding shares of the Corporation, voting together as a single class, shall be required to alter, amend, repeal or adopt any provision inconsistent with this Section 13. ARTICLE III BOARD OF DIRECTORS Section 1. (a) Number, Election and Terms of Directors. The business and affairs of the Corporation shall be managed by a Board of Directors which shall consist of not less than three (3) nor more than twelve (12) persons, who need not be residents of the State of Nevada or stockholders of the Corporation. 7 The exact number of directors within the minimum and maximum limitations specified in the preceding sentence shall be fixed from time to time by the Board of Directors pursuant to a resolution adopted by a majority of the entire Board of Directors. The directors shall be divided into three classes, as nearly equal in number as possible, with the term of office of the first class to expire at the 1996 Annual Meeting of Stockholders, the term of office of the second class to expire at the 1997 Annual Meeting of Stockholders and the term of office of the third class to expire at the 1998 Annual Meeting of Stockholders. At each Annual Meeting of Stockholders following such initial classification and election, directors elected to succeed those directors whose terms expire shall be elected for a term of office to expire at the third succeeding Annual Meeting of Stockholders after their election. (b) Newly Created Directorships. A directorship to be filled by reason of any increase in the number of directors may be filled (i) by election at an annual or special meeting of stockholders called for that purpose or (ii) by the Board of Directors for a term of office continuing only until the next election of one or more directors by the stockholders- provided that the Board of Directors may not fill more than two such directorships during the period between any two successive annual meetings of stockholders. (c) Vacancies in the Board of Directors. Any vacancies in the Board of Directors resulting from death, resignation, retirement, disqualification, removal from office or other cause shall be filled by a majority vote of the directors then in office, and directors so chosen shall hold office for a term expiring at the annual meeting of stockholders at which the term of the class to which they have been elected expires. No decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director. (d) Removal of Directors. Any director, or the entire Board of Directors, may be removed from office at any time, but only for cause and only by the affirmative vote of the holders of at least 80% of the voting power of the then outstanding shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class. (e) Amendment, Repeal, etc. Notwithstanding any other provisions of the Articles of Incorporation or the Bylaws of the Corporation (and notwithstanding the fact that a lesser percentage may be specified by law, the Articles of incorporation or the Bylaws of the Corporation), the affirmative vote of the holders of at least 80% of the voting power of the then outstanding shares of the Corporation, voting together as a single class, shall be required to alter, amend, repeal or adopt any provision inconsistent with this Section 1. Section 2. Quorum. Unless otherwise provided in the Articles of Incorporation, a majority of the total number of directors shall constitute a quorum for the transaction of business of the Board of Directors and the vote of a majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors. 8 Section 3. Place of Meetings, Order of Business. The directors may hold their meetings and may have an office and keep the books of the Corporation, except as otherwise provided by law, in such place or places, within or without the State of Nevada, as the Board of Directors may from time to time determine by resolution. The meetings of the Board of Directors shall be presided over by the Chairman of the Board, or if he is not present, by the President, and the business of the meeting shall be transacted in such order as shall from time to time be determined by the Chairman of the Board, or in his absence, by the President, or by resolution of the Board of Directors. Section 4. First Meeting. Each newly elected Board of Directors may hold its first meeting for the purpose of organization and the transaction of business, if a quorum is present, immediately after and at the same place as the annual meeting of the stockholders. Notice of such meeting shall not be required. At the first meeting of the Board of Directors in each year at which a quorum shall be present, held next after the annual meeting of stockholders, the Board of Directors shall proceed to the election of the officers of the Corporation. Section 5. Regular Meetings. Regular meetings of the Board of Directors shall be held at such times and places as shall be designated from time to time by resolution of the Board of Directors. Notice of such regular meetings shall not be required. Section 6. Special Meetings. Special meetings of the Board of Directors may be called by the Chairman of the Board, the President or on the written request of any two directors, by the Secretary, in each case on at least twenty-four (24) hours personal, written, telegraphic, cable or wireless notice to each directors. Such notice, or any waiver thereof pursuant to Article VIII, Section 3 hereof, need not state the purpose or purposes of such meeting, except as may otherwise be required by law or provided for in the Articles of Incorporation or these Bylaws. Section 7. Compensation. Unless otherwise restricted by the Articles of Incorporation, the Board of Directors shall have the authority to fix the compensation of directors. Section 8. Action Without a Meeting; Telephone Conference Meeting. Unless otherwise restricted by the Articles of Incorporation, any action required or permitted to be taken at any meeting of the Board of Directors, or any committee designated by the Board of Directors, may be taken without a meeting if all members of the Board of Directors or committee, as the case may be, either originally or in counterparts, consent thereto in writing. Such consent shall have the same force and effect as a unanimous vote at a meeting, and may be stated as such in any document or instrument filed with the Secretary of State of Nevada. Unless otherwise restricted by the Articles of Incorporation, subject to the requirement for notice of meetings, members of the Board of Directors, or members of any committee designated by the Board of Directors, may participate in a meeting of such Board of Directors or committee, as the case may be, by means of a conference telephone or similar communications equipment by means of 9 which all persons participating in the meeting can hear each other, and participation in such a meeting shall constitute presence in person at such meeting, except where a person participates in the meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called or convened. Section 9. Approval or Ratification of Acts or Contracts by Stockholders. The Board of Directors in its discretion may submit any act or contract for approval or ratification at any annual meeting of the stockholders, or at any special meeting of the stockholders called for the purpose of considering any such act or contract, and any act or contract that shall be approved or be ratified by the vote of the stockholders holding a majority of the issued and outstanding shares of stock of the Corporation entitled to vote and present in person or by proxy at such meeting (provided that a quorum is present), shall be as valid and as binding upon the Corporation and upon all the stockholders as if it has been approved or ratified by every stockholder of the Corporation. In addition, any such act or contract may be approved or ratified by the written consent of stockholders holding a majority of the issued and outstanding shares of capital stock of the Corporation entitled to vote and such consent shall be as valid and as binding upon the Corporation and upon all the stockholders as if it had been approved or ratified by every stockholder of the Corporation. ARTICLE IV COMMITTEES Section 1. Designation; Powers. The Board of Directors may, by resolution passed by a majority of the whole board, designate one or more committees, including, if they shall so determine, an executive committee, each such committee to consist of one or more of the directors of the Corporation. Any such designated committee shall have and may exercise such of the powers and authority of the Board of Directors in the management of the business and affairs of the Corporation as may be provided in such resolution, except that no such Committee shall have the power or authority of the Board of Directors in reference to amending the Articles of Incorporation, adopting an agreement of merger or consolidation, recommending to the stockholders the sale, lease or exchange of all or substantially all of the Corporation's property and assets, recommending to the stockholders a dissolution of the Corporation or a revocation of a dissolution of the Corporation, or amending, altering or repealing the Bylaws or adopting new Bylaws for the Corporation and, unless such resolution or the Articles of Incorporation expressly so provides, no such committee shall have the power or authority to declare a dividend or to authorize the issuance of stock. Any such designated committee may authorize the seal of the Corporation to be affixed to all papers which may require it. In addition to the above, such committee or committees shall have such other powers and limitations of authority as may be determined from time to time by resolution adopted by the Board of Directors. Section 2. Procedure; Meetings, Quorum. Any committee designated pursuant to Section I of this Article shall choose its own chairman, shall keep regular minutes of its proceedings and report the same to the Board of Directors when requested, shall fix its own rules or procedures, and shall meet at such 10 times and at such place or places as may be provided by such rules, or by resolution of such committee or resolution of the Board of Directors. At every meeting of any such committee, the presence of a majority of all the members thereof shall constitute a quorum and the affirmative vote of a majority of the members present shall be necessary for the adoption by it of any resolution. Section 3. Substitution of Members. The Board of Directors may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of such committee. In the absence or disqualification of a member of a committee, the member or members present at any meeting and not disqualified from voting, whether or not constituting a quorum, may unanimously appoint another member of the Board of Directors to act at the meeting in the place of the absent or disqualified member. 11 ARTICLE V OFFICERS Section 1. Number, Titles and Term of Office. The officers of the Corporation shall be a President, one or more Vice Presidents (any one or more of whom may be designated Executive Vice President or Senior Vice President), a Treasurer, a Secretary, a Registered Agent and, if the Board of Directors so elects, a Chairman of the Board and such other officers as the Board of Directors may from time to time elect or appoint. Each officer shall hold office until his successor shall be duly elected and shall qualify or until his death or until he shall resign or shall have been removed in the manner hereinafter provided. Any number of offices may be held by the same person, unless the Articles of Incorporation provides otherwise. Except for the Chairman of the Board, if any, no officers need be a director. Section 2. Salaries. The salaries or other compensation of the officers and agents of the Corporation shall be fixed from time to time by the Board of Directors. Section 3. Removal. Any officer or agent elected or appointed by the Board of Directors may be removed, either with or without cause, by the vote of a majority of the whole Board of Directors at a special meeting called for the purpose, or at any regular meeting of the Board of Directors, provided the notice for such meeting shall specify that the matter of any such proposed removal will be considered at the meeting but such removal shall be without prejudice to the contract rights, if any, of the person so removed. Election or appointment of an officer or agent shall not of itself create contract rights. Section 4. Vacancies. Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors. Section 5. Powers and Duties of the Chief Executive Officer. The President shall be the chief executive officer of the Corporation unless the Board of Directors designates the Chairman of the Board as chief executive officer. Subject to the control of the Board of Directors and the executive committee (if any), the chief executive officer shall have general executive charge, management and control of the properties, business and operations of the Corporation with all such powers as may be reasonably incident to such responsibilities; he may agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Corporation and may sign all certificates for shares of capital stock of the Corporation and shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to him by the Board of Directors. Section 6. Powers and Duties of the Chairman of the Board. The Chairman of the Board shall have no administrative duties relating to the Corporation or its property and he shall act as a consultant and advisor to the President. The Chairman of the Board shall preside when present at meetings of the stockholders and the Board of Directors. In addition, he shall exercise such other powers and 12 perform such other duties as may be assigned to him from time to time by the Board of Directors or as may be prescribed by the Bylaws. Section 7. Powers and Duties of the President. Unless the Board of Directors otherwise determines, the President shall have the authority to agree upon and execute all leases, contracts, evidences of indebtedness and other obligations in the name of the Corporation; and he shall have such other powers and duties as designated in accordance with these Bylaws and as from time to time may be assigned to him by the Board of Directors. Section 8. Vice Presidents. In the absence of the President, or in the event of his inability or refusal to act, a Vice President designated by the Board of Directors shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions of the President. In the absence of a designation by the Board of Directors of a Vice President to perform the duties of the President, or in the event of his absence or inability or refusal to act, the Vice President who is present and who is senior in terms of time as a Vice President of the Corporation shall so act. The Vice Presidents shall perform such other duties and have such other powers as the chief executive officer or the Board of Directors may from time to time prescribe. Section 9. Treasurer. The Treasurer shall have responsibility for the custody and control of all the funds and securities of the Corporation, and he shall have such other powers and duties as designated in these Bylaws and as from time to time may be assigned to him by the Board of Directors. He shall perform all acts incident to the position of Treasurer, subject to the control of the chief executive officer and the Board of Directors; and he shall, if required by the Board of Directors, give such bond for the faithful discharge of his duties in such form as the Board of Directors may require. Section 10. Assistant Treasurers. Each Assistant Treasurer shall have the usual powers and duties pertaining to his office, together with such other powers and duties as designated in these Bylaws and as from time to time may be assigned to him by the chief executive officer or the Board of Directors. The Assistant Treasurers shall exercise the powers of the Treasurer during that officer's absence or inability or refusal to act. Section 11. Secretary. The Secretary shall keep the minutes of all meetings of the Board of Directors, committees of directors and the stockholders, in books provided for that purpose; he shall attend to the giving and serving of all notices; he may in the name of the Corporation affix the seal of the Corporation to all contracts of the Corporation and attest the affixation of the seal of the Corporation thereto; he may sign with the other appointed officers all certificates for shares of capital stock of the Corporation; he shall have charge of the certificate books, transfer books and stock ledgers, and such other books and papers as the Board of Directors may direct, all of which shall at all reasonable times be open to inspection of any director upon application at the office of the Corporation during business hours; he shall have such other powers and duties as designated in these Bylaws and as from time to time may be assigned to him by the Board of Directors; and he shall in 13 general perform all acts incident to the office of Secretary, subject to the control of the chief executive officer and the Board of Directors. Section 12. Assistant Secretaries. Each Assistant Secretary shall have the usual powers and duties pertaining to his office, together with such other powers and duties as designated in these Bylaws and as from time to time may be assigned to him by the chief executive officer or the Board of Directors. The Assistant Secretaries shall exercise the powers of the Secretary during that officer's absence or inability or refusal to act. Section 13. Resident Agent. The Resident Agent shall be either a natural person or a corporation, resident or located in the State of Nevada. Along with all other powers authorized by law, the Articles of Incorporation or these Bylaws the Registered Agent may accept legal process, demand or notice authorized by law to be served upon the Corporation. Section 14. Action with Respect to Securities of Other Corporations. Unless otherwise directed by the Board of Directors, the chief executive officer shall have the power to vote and otherwise act on behalf of the Corporation, in person or by proxy, at any meeting of security holders of or with respect to any action of security holders of any other corporation in which this Corporation may hold securities and otherwise to exercise any and all rights and powers which this Corporation may possess by reason of its ownership of securities in such other corporations. ARTICLE VI INDEMNIFICATION OF DIRECTORS, OFFICERS, EMPLOYEES AND AGENTS Section 1. To the fullest extent allowed by Nevada law, any director of the Corporation shall not be liable to the corporation or its shareholders for monetary damages for an act or omission in the director's capacity as a director, except that this Article VI does not eliminate or limit the liability of a director for: (a) an act or omission which involves intentional misconduct, fraud or a knowing violation of law; or (b) the payment of dividends in violation of N.R.S. 78.300. Section 2. The Corporation shall indemnify each director, officer, agent and employee, now or hereafter serving the Corporation, each former director, officer, agent and employee, and each person who may now or hereafter serve or who may have heretofore served at the Corporation's request as a director, officer, agent or employee of another corporation or other business enterprise, and the respective heirs, executors, administrators and personal representatives of each of them against all expenses actually and reasonably incurred by, or imposed upon, him in connection with the defense of any claim, action, suit or proceeding, civil or criminal against him by reason of his being or having been such director, officer, agent or employee, except in relation to 14 such matters as to which he shall be adjudged by a court of competent jurisdiction after exhaustion of all appeals therefrom in such action, suit or proceedings to be liable for gross negligence or willful misconduct in the performance of duty. For purposes hereof, the term "expenses" shall include but not be limited to all expenses, costs, attorneys' fees, judgments (including adjudications other than on the merits), fines, penalties, arbitration awards, costs of arbitration and sums paid out and liabilities actually and reasonably incurred or imposed in connection with any suit, claim, action or proceeding, and any settlement or compromise thereof approved by the Board of Directors as being in the best interests of the Corporation. However, in any case in which there is no disinterested majority of the Board of Directors available, the indemnification shall be made: (1) only if the Corporation shall be advised in writing by counsel that in the opinion of counsel (a) such officer, director, agent or employee was not adjudged or found liable for gross negligence or willful misconduct in the performance of duty as such director, officer, agent or employee or the indemnification provided is only in connection with such matters as to which the person to be indemnified was not so liable, and in the case of settlement or compromise, the same is in the best interests of the Corporation; and (b) indemnification under the circumstances is lawful and falls within the provisions of these Bylaws and (2) only in such amount as counsel shall advise the Corporation in writing is, in his opinion, proper. In making or refusing to make any payment under this or any other provisions of these Bylaws, the Corporation, its directors, officers, employees and agents shall be fully protected if they rely upon the written opinion of counsel selected by, or in the manner designated by, the Board of Directors. Section 3. Expenses incurred in defending a civil or criminal action, suit or proceeding may be paid by the Corporation in advance of the final disposition of such action, suit or proceeding as authorized by the Board upon receipt of an undertaking by or on behalf of the director, officer, employee or agent to repay such amount unless it shall ultimately be determined that he is entitled to be indemnified by the Corporation as authorized in these Bylaws. Section 4. The Corporation may indemnify each person, though he is not or was not a director, officer, employee or agent of the Corporation, who served at the request of the Corporation on a committee created by the Board to consider and report to it in respect of any matter. Any such indemnification may be made under the provisions hereof and shall be subject to the limitations hereof, except that (as indicated) any such committee member need not be nor have been a director, officer, employee or agent of the Corporation. Section 5. The provisions hereof shall be applicable to actions, suits or proceedings (including appeals) commenced after the adoption hereof, whether arising from acts or omissions to act occurring before or after the adoption hereof Section 6. The indemnification provisions herein provided shall not be deemed exclusive of any other rights to which those indemnified may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors or otherwise, or by law or statute, both as to action in his official capacity and as to action in another capacity while holding such office, and shall continue as to a person who has ceased to be a director, officer, employee or Agent and 15 shall inure to the benefit of the heirs, executors and administrators of such a person. Section 7. The Corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, and persons described in Section 4 of this Article above, against any liability asserted against him and incurred by him in any such capacity or arising out of his status as such, whether or not the Corporation would have the power to indemnity him against such liability under the provisions of these Bylaws. ARTICLE VII CAPITAL STOCK Section 1. Certificates of Stock. The certificates for shares of the capital stock of the Corporation shall be in such form, not inconsistent with that required by law and the Articles of Incorporation, as shall be approved by the Board of Directors. The President or a Vice President shall cause to be issued to each stockholder one or more certificates, under the seal of the Corporation or a facsimile thereof if the Board of Directors shall have provided for such seal, and signed by the President or a Vice President and the Secretary or an Assistant Secretary or the Treasurer or an Assistant Treasurer certifying the number of shares (and, if the stock of the Corporation shall be divided into classes or series, the class and series of such shares) owned by such stockholder in the Corporation; provided however, that any of or all the signatures on the certificate may be facsimile. The stock record books and the blank stock certificate books shall be kept by the Secretary, or at the office of such transfer agent or transfer agents as the Board of Directors may from time to time by resolution determine. In case any officer, transfer agent or registrar who shall have signed or whose facsimile signature or signatures shall have been placed upon any such certificate or certificates shall have ceased to be such officer, transfer agent or registrar before such certificate is issued by the Corporation, such certificate may nevertheless be issued by the Corporation with the same effect as if such person were such officer, transfer agent or registrar at the date of issue. The stock certificates shall be consecutively numbered and shall be entered in the books of the Corporation as they are issued and shall exhibit the holder's name and number of shares. Section 2. Transfer of Shares. The shares of stock of the Corporation shall be transferable only on the books of the Corporation by the holders thereof in person or by their duly authorized attorneys or legal representatives upon surrender and cancellation of certificates for a like number of shares. Upon surrender to the Corporation or a transfer agent of the Corporation of a certificate for shares duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, it shall be the duty of the Corporation to issue a new certificate to the person entitled thereto, cancel the old certificate and record the transaction upon its books. 16 Section 3. Ownership of Shares. The Corporation shall be entitled to treat the holder of record of any share or shares of capital stock of the Corporation as the holder in fact thereof and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise provided by the laws of the State of Nevada. Section 4. Regulations Regarding Certificates. The Board of Directors shall have the power and authority to make all such rules, restrictions and regulations as they may deem expedient concerning the issue, transfer and registration or the replacement of certificates for shares of capital stock of the Corporation. Section 5. Lost or Destroyed Certificates. The Board of Directors may determine the conditions upon which a new certificate of stock may be issued in place of a certificate which is alleged to have been lost, stolen or destroyed; and may, in their discretion, require the owner of such certificate or his legal representative to give bond, with sufficient surety, to indemnity the Corporation and each transfer agent and registrar against any and all losses or claims which may arise by reason of the issue of a new certificate in the place of the one so lost, stolen or destroyed. ARTICLE VIII MISCELLANEOUS PROVISIONS Section 1. Fiscal Year. The fiscal year of the Corporation shall be such as established from time to time by the Board of Directors. Section 2. Corporate Seal. The Board of Directors may provide a suitable seal containing the name of the Corporation. The Secretary shall have charge of the seal (if any). If and when so directed by the Board of Directors or a committee thereof, duplicates of the seal may be kept and used by the Treasurer or by the Assistant Secretary or Assistant Treasurer. Section 3. Notice and Waiver of Notice. Whenever any notice is required to be given by law, the Articles of Incorporation or under the provisions of these Bylaws, said notice shall be deemed to be sufficient if given (i) by telegraphic, cable, electronic mail or wireless transmission or (ii) by deposit of the same in a post office box in a sealed prepaid wrapper addressed to the person entitled thereto at his post office address, as it appears on the records of the Corporation, and such notice shall be deemed to have been given on the day of such transmission or mailing as the case may be. Whenever notice is required to be given by law, the Articles of Incorporation or under any of the provisions of these Bylaws, a written waiver thereof, signed by the person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a person at a meeting shall constitute a waiver of notice of such meeting, except when the person attends a meeting for the express purpose of objecting, at the 17 beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the stockholders, directors, or members of a committee of directors need be specified in any written waiver of notice unless so required by the Articles of Incorporation or the Bylaws. Section 4. Resignations. Any director, member of a committee or officer may resign at any time. Such resignation shall be made in writing and shall take effect at the time specified therein, or if no time be specified, at the time of its receipt by the chief executive officer or Secretary. The acceptance of a resignation shall not be necessary to make it effective, unless expressly so provided in the resignation. Section 5. Facsimile Signatures. In addition to the provisions for the use of facsimile signatures elsewhere specifically authorized in these Bylaws, facsimile signatures of any officer or officers of the Corporation may be used whenever and as authorized by the Board of Directors. Section 6. Reliance Upon Books, Reports and Records. Each director and each member of any committee designated by the Board of Directors shall, in the performance of his duties, be fully protected in relying in good faith upon the books of account or reports made to the Corporation by any of its officers, or by an independent certified public accountant, or by an appraiser selected with reasonable care by the Board of Directors or by any such committee, or in relying in good faith upon other records of the Corporation. ARTICLE IX AMENDMENTS The Board of Directors shall have the power to adopt, amend and repeal from time to time the Bylaws of the Corporation, subject to the right of the stockholders entitled to vote by law with respect thereto to amend or repeal such Bylaws as adopted or amended by the Board of Directors; provided, however, that in the case of amendments by stockholders or any repeal by stockholders, notwithstanding any other provisions of these Bylaws or any other provision of law which might otherwise permit a lesser vote or no vote, but in addition to any affirmative vote of the holders of any particular class or series of the capital stock of the Corporation required by law, the Articles of Incorporation or these Bylaws, the affirmative vote of the holders of at least 80 percent of the voting power of the then outstanding shares of the Corporation entitled to vote, voting together as a single class, shall be required to alter, amend or repeal any provision of these Bylaws. 18 EX-10 3 mirantagr.txt ================================================================================ Exhibit 10.21 CREDIT AGREEMENT GREY WOLF EXPLORATION INC. as Borrower - and - MIRANT CANADA ENERGY CAPITAL, LTD. as Lender ================================================================================ December 20, 2001 TABLE OF CONTENTS Page Article 1 DEFINITIONS AND ACCOUNTING TERMS 1.1 Defined Terms........................................................1 1.2 Use of Defined Terms................................................18 1.3 Cross-References....................................................18 1.4 Accounting and Financial Determinations.............................19 1.5 Statutes, Regulations and Rules.....................................19 1.6 Monetary References.................................................19 1.7 Schedules and Exhibits..............................................19 Article 2 COMMITMENT AND LOAN PROCEDURES 2.1 Commitment..........................................................19 2.2 Maximum Commitment Amount and Commitment Amount.....................20 2.3 Loan Procedure......................................................20 2.4 Records 21 Article 3 REPAYMENTS, PREPAYMENTS, INTEREST AND FEES 3.1 Repayments and Prepayments..........................................21 3.2 Refinancing.........................................................22 3.3 Interest Provisions.................................................22 3.4 Collateral Account..................................................23 3.5 Closing Fee.........................................................25 3.6 Engineering Fee.....................................................25 Article 4 TAXES AND OTHER PROVISIONS 4.1 Payments, Computations, etc.........................................25 4.2 Setoff ...........................................................25 4.3 Right of First Refusal - Proposed Undertakings......................26 4.4 Right of First Refusal-Proposed Non-Subject Interest Undertaking....27 4.5 Use of Proceeds.....................................................28 Article 5 CONDITIONS TO LOANS 5.1 Initial Loan........................................................29 5.2 Resolutions, etc....................................................29 5.3 Override Royalty Agreement..........................................29 5.4 Security 29 5.5 Release and Discharge...............................................30 i 5.6 After-Acquired Property.............................................30 5.7 Memorandum of Purchase Contracts....................................30 5.8 Opinion of Counsel..................................................30 5.9 Certified Copy of Farmout Amending Agreement........................30 5.10 Development Plan and Schedules......................................30 5.11 Evidence of Insurance...............................................30 5.12 Approvals...........................................................31 5.13 Compliance with Loan Documents......................................31 5.14 No Default..........................................................31 5.15 Engineering.........................................................31 5.16 Environmental.......................................................31 5.17 Officer's Certificate...............................................31 5.18 Release of Liens....................................................31 5.19 Closing Fees, Expenses, etc.........................................32 5.20 ISDA Master Agreement...............................................32 5.21 Documents...........................................................32 5.22 Other Legal Matters.................................................32 5.23 All Loans...........................................................32 Article 6 REPRESENTATIONS AND WARRANTIES 6.1 Representations.....................................................33 6.2 Organization........................................................33 6.3 Due Authorization, Non-Contravention, etc...........................33 6.4 Government Approval, Regulation, etc................................34 6.5 Validity, etc.......................................................34 6.6 Financial Information...............................................34 6.7 No Material Adverse Change..........................................34 6.8 Litigation, Labor Controversies, etc................................34 6.9 Subsidiaries........................................................34 6.10 Borrower's Shares...................................................34 6.11 Subject Interests...................................................34 6.12 Oil and Gas Leases..................................................35 6.13 Preferential Rights.................................................35 6.14 Balancing and Take-or-Pay Contracts.................................35 6.15 Production Requirements.............................................36 6.16 Facilities..........................................................36 6.17 Broker's Fees.......................................................36 6.18 Taxes ...........................................................36 ii 6.19 Compliance with Laws................................................36 6.20 Environmental Warranties............................................36 6.21 Accuracy of Information.............................................37 6.22 No Prohibition on Perfection........................................38 6.23 Solvency 38 6.24 Insurance...........................................................38 6.25 No Default..........................................................38 6.26 Farmout Lands.......................................................38 Article 7 AFFIRMATIVE COVENANTS 7.1 Affirmative Covenants...............................................38 7.2 Punctual Payment....................................................38 7.3 Financial Information, Reports, Notices, etc........................38 7.4 Gathering and Transportation and Other Services.....................42 7.5 Collateral Coverage Deficiency or Collateral Coverage Default.......43 7.6 Use of Proceeds.....................................................43 7.7 Joint Operating Agreement...........................................43 7.8 Compliance with Laws................................................43 7.9 Production-Related Expenses and Taxes...............................44 7.10 Operation of Subject Interests......................................44 7.11 Development Plan....................................................45 7.12 Insurance...........................................................45 7.13 Accounting Principles...............................................46 7.14 Books and Records; Inspections......................................46 7.15 Environmental Covenant..............................................46 7.16 Board of Directors Meetings.........................................47 7.17 Hedging Agreements..................................................47 7.18 Protection of Security..............................................47 7.19 Grant Fixed Charge Security.........................................47 7.20 Further Assurances..................................................48 7.21 Override Records....................................................49 7.22 Title Deficiencies..................................................49 7.23 Further Due Diligence...............................................49 Article 8 NEGATIVE COVENANTS 8.1 Negative Covenants..................................................50 8.2 Business Activities.................................................50 iii 8.3 Indebtedness........................................................50 8.4 Liens ...........................................................50 8.5 Restricted Payments, etc............................................50 8.6 Capital Expenditures................................................51 8.7 Accounts Receivable.................................................51 8.8 Rental Obligations..................................................51 8.9 Take-or-Pay Contracts...............................................51 8.10 Consolidation, Merger, etc..........................................51 8.11 Asset Dispositions, etc.............................................51 8.12 Abandonment of Wellbores or Conduct of Certain Operations...........52 8.13 Grant Liens, Mortgage or Transfer or Resignation as Operator of any Subject Interest.............................................52 8.14 Modification of Certain Agreements..................................52 8.15 Pension Plans.......................................................52 8.16 Other Agreements....................................................53 8.17 No Subsidiaries.....................................................53 8.18 No Other Hedging Agreements.........................................53 8.19 Transactions with Affiliates........................................53 8.20 Negative Pledges, Restrictive Agreements, etc.......................53 8.21 Limitations on Certain Financing Leases and Sale and Leaseback Transactions..............................................53 8.22 Dissemination of Information........................................54 8.23 Subject Interests...................................................54 Article 9 EVENTS OF DEFAULT 9.1 Events of Default...................................................54 (a) Non-Payment of Obligations.................................54 (b) Breach of Warranty.........................................54 (c) Non-Performance of Certain Covenants and Obligations.......54 (d) Collateral Coverage Default................................54 (e) Default on Other Indebtedness..............................55 (f) Judgments .........................................55 (g) Control of Borrower........................................55 (h) Bankruptcy, Insolvency.....................................55 (i) Winding-Up .........................................56 (j) Impairment of Security, etc................................56 (k) Cumulative Reimbursable Expenses Amount....................56 (l) Material Adverse Change....................................56 (m) Dissemination of Information...............................56 iv 9.2 Remedies of Lender..................................................56 Article 10 OVERRIDE ROYALTY AGREEMENT 10.1 Override Royalty Agreement..........................................60 Article 11 HYDROCARBON PURCHASE TERMS AND PROVISIONS 11.1 General.............................................................60 11.2 Marketing Subject Hydrocarbons to Third Persons.....................61 Article 12 MISCELLANEOUS PROVISIONS 12.1 Waivers, Amendments, etc............................................61 12.2 Notices.............................................................61 12.3 Payment of Costs and Expenses.......................................62 12.4 Indemnification.....................................................62 12.5 Survival............................................................63 12.6 Inconsistency.......................................................64 12.7 Reimbursable Expenses...............................................64 12.8 Severability........................................................64 12.9 Headings............................................................64 12.10 Limitation on Liability.............................................64 12.11 Intentions of the Parties...........................................64 12.12 Governing Law; Entire Agreement.....................................64 12.13 Successors and Assigns..............................................64 12.14 Effect of Syndication...............................................65 12.15 Participations......................................................65 12.16 Maximum Rate of Return..............................................65 12.17 Waiver of Judgment Interest Act (Alberta)...........................66 12.18 Deemed Reinvestment Not Applicable..................................66 12.19 Confidentiality.....................................................66 12.20 Other Transactions..................................................66 12.21 Forum Selection and Consent to Jurisdiction.........................66 12.22 Waiver of Jury Trial................................................67 12.23 No Oral Agreements..................................................67 12.24 Execution in Counterparts, Effectiveness............................67 v 1 CREDIT AGREEMENT This Credit Agreement dated as of December 20, 2001, BETWEEN: GREY WOLF EXPLORATION INC., a corporation incorporated pursuant to the laws of Alberta, as Borrower - and - MIRANT CANADA ENERGY CAPITAL, LTD., a corporation incorporated pursuant to the laws of New Brunswick, as Lender RECITALS A. Borrower is engaged directly in the business of acquiring, owning and operating certain oil and gas leasehold and other interests in Western Canada. B. Borrower desires to obtain the Commitment from Lender pursuant to which Loans, in a maximum aggregate principal amount of $150,000,000 and with a Commitment Amount as of the Effective Date of $40,000,000, will be made to Borrower from Lender prior to the Commitment Termination Date. C. Lender is willing, subject to the terms and conditions herein set forth to make Loans to Borrower pursuant to the Commitment. D. The Loan proceeds will be used (i) to repay existing Indebtedness, (ii) to develop the Subject Interests in accordance with the Development Plan, and (iii) for general business purposes and working capital purposes of Borrower consistent with the Development Plan and any other purposes as agreed by Lender and Borrower. NOW THEREFORE for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows: Article 1 DEFINITIONS AND ACCOUNTING TERMS 1.1 Defined Terms. The following terms when used in this Agreement, including its recitals, schedules and exhibits, shall, except where the context otherwise requires, have the following meanings (such meanings to be equally applicable to the singular and plural forms thereof): "Abraxas Amalgamation" means the amalgamation between Abraxas Acquisition Corporation and Borrower to be completed on or before January 1, 2002. 2 "Acceptable Proved Reserves" means Proved Reserves located in the Subject Interests that (i) have been evaluated by the Approved Independent Engineer and are included in the most recent Independent Engineering Report, (ii) are determined by Lender, in its sole and absolute discretion, to have satisfactory title, including Liens in favour of Lender and title opinions or other assurances of title satisfactory to Lender, if required by Lender (iii) are free of any Liens except for any Permitted Liens, and (iv) are covered by environmental reports, if required by Lender, which have been delivered to Lender and Lender has determined, in its reasonable discretion, that the results of such environmental reports are satisfactory. "Accountant" has the meaning set forth in Section 7.3(b). "Additional Development Program Option" has the meaning set forth in Section 4.3(b). "Affiliate" has the meaning attributed to it in the Business Corporations Act (Alberta). "Agreement" means, on any date, this Credit Agreement as originally in effect on the Effective Date and as thereafter from time to time amended, supplemented, amended and restated, or otherwise modified and in effect on such date. "Applicable Law" means with respect to any Person or matter, any federal, state, provincial, municipal, regional, tribal or local statute, law, code, rule, regulation, treaty, convention, application, order, decree, consent decree, injunction, directive, determination or other requirement (domestic, foreign or international and whether or not having the force of law) relating to such Person or matter and, where applicable, any interpretation thereof by a Governmental Agency having jurisdiction with respect thereto or charged with the administration or interpretation thereof. "Approvals" means each and every approval, authorization, license, permit, consent, variance, land use entitlement, franchise, agreement, filing or registration by or with any Governmental Agency or other Person necessary for all stages of acquiring, developing, operating, maintaining and abandoning Property, including the Subject Properties. "Approved Capital Expenditures" means, for purposes of calculating Net Cash Flow, capital expenditures specified in relation to a particular portion of the Subject Interests which are approved by Lender as part of the "PUD Capex (net)", "PDNP Capex (net)" and "Other Capital Expenditures (net)" sections, respectively, of the Development Plan and which only include the capital expenditures specified in relation to such portion of the Subject Interests in the "PUD Capex (net)", "PDNP Capex (net)" and "Other Capital Expenditures (net)" sections, respectively, of the Development Plan; provided, however, that, Approved Capital Expenditures reimbursed to Borrower shall not exceed the lesser of (i) Approved Capital Expenditures actually expended by Borrower for such period and (ii) the amount set forth in the "PUD Capex (net)", "PDNP Capex (net)" and "Other Capital Expenditures (net)" sections, respectively, of the Development Plan for such period. Unless specifically approved by Lender, any capital expenditures which fall 3 outside the above limitations shall be paid by Borrower and such capital expenditures will not be included in Approved Capital Expenditures. "Approved Independent Engineer" means McDaniel & Associates Consultants Ltd., or another independent petroleum engineer, selected by Borrower and acceptable to Lender, in its sole discretion; provided that Gilbert Laustsen Jung Associates Ltd., Outrim Szabo, Fekete Associates Inc., DeGolyer and MacNaughton, Ryder Scott Co. Petroleum Consultants and Sproule & Associates Limited are all acceptable to Lender. "Approved G&A Expenses" means, for purposes of calculating Net Cash Flow, general and administrative expenses specified in relation to a particular portion of the Subject Interests and closing costs associated with this Agreement, reporting costs incurred under this Agreement for engineering and accounting reports and such other fees incurred by Borrower under this Agreement, which are approved by Lender as part of the "Approved G&A Expenses" section of the Development Plan; provided, however, that, unless otherwise specifically approved by Lender, Approved G&A Expenses reimbursed to Borrower shall not exceed the amount set forth in the "Approved G&A Expenses" section of the Development Plan for such period. Unless specifically approved by Lender, any general and administrative expenses which fall outside the above limitations shall be paid by Borrower and such general and administrative expenses will not be included in Approved G&A Expenses. "Approved Lease Operating Expenses" means, for purposes of calculating Net Cash Flow, production-related expenses specified in relation to a particular portion of the Subject Interests which are approved by Lender as part of the "Operating Expenses" section of the Development Plan and which only include the production-related expenses specified in relation to such portion of the Subject Interests in the "Operating Expenses" section of the Development Plan; provided, however, that, Approved Lease Operating Expenses reimbursed to Borrower shall not exceed the lesser of (i) Approved Lease Operating Expenses actually expended by Borrower for such period and (ii) the amount set forth in the "Operating Expenses" section of the Development Plan for such period. Unless specifically approved by Lender, any production-related expenses which fall outside the above limitations shall be paid by Borrower and such production-related expenses will not be included in Approved Lease Operating Expenses. "Approved Third-Party Transportation, Gathering and Marketing Expenses" means, for purposes of calculating Net Cash Flow, third-party transportation, gathering and marketing related expenses specified in relation to a particular portion of the Subject Interests which are approved by Lender and which only include the third-party transportation, gathering and marketing-related expenses specified in relation to such portion of the Subject Interests; provided, however, that Approved Third-Party Transportation, Gathering and Marketing Expenses reimbursed to Borrower shall not exceed Approved Third-Party Transportation, Gathering and Marketing Expenses actually expended by Borrower for such period. Unless specifically approved by Lender, any third-party transportation, gathering and marketing-related expenses which fall outside the above limitations shall be paid by Borrower and 4 such third-party transportation, gathering and marketing-related expenses will not be included in Approved Third-Party Transportation, Gathering and Marketing Expenses. "Authorized Officer" means, relative to any Obligor, those of its officers whose signatures and incumbency shall have been certified to Lender pursuant to Section 5.2. "Borrower" means Grey Wolf Exploration Inc. and its successors and permitted assigns. "Borrower Hedging Agreements" means each of (i) the Initial Hedging Agreements and (ii) any other Hedging Agreement entered into between Borrower and Lender or its Affiliates. "Broker's Fee" means any obligation or liability of any kind, contingent or otherwise, for any broker's, finders' or similar fees. "Business Day" means any day which is neither a Saturday or Sunday nor a legal holiday on which banks are authorized or required to be closed in Calgary, Alberta. "Capital Expenditures" means, for any period, the sum of (i) the aggregate amount of all expenditures of Borrower for fixed or capital assets made during such period which, in accordance with GAAP, would be classified as capital expenditures, and (ii) the aggregate amount of all Capitalized Lease Liabilities incurred during such period. "Capitalized Lease Liabilities" means the aggregate amount of all monetary obligations of Borrower and its Subsidiaries under any leasing or similar arrangement which, in accordance with GAAP, would be classified as capitalized leases, and, for purposes of this Agreement and each other Loan Document, the amount of such obligations shall be the capitalized amount thereof, determined in accordance with GAAP, and the stated maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be terminated by the lessee without payment of a penalty. "Cash Flow from Override" means, for any period and for each Override Royalty Agreement in effect at such time, proceeds payable to the owner of the Override pursuant to such Override Royalty Agreements for the life of the Subject Interests, which for greater certainty includes (i) any Subject Interest in respect of which Lender has exercised its Additional Development Program Option, and (ii) any replacement or offset well within the Subject Interests that produces Hydrocarbons that may be deemed to have been recovered by a well funded under this Agreement, or by a Subject Interest in which a well funded by this Agreement is located. "Change of Control" means if any Person, other than Abraxas Petroleum Corporation or Canadian Abraxas Petroleum Limited or their Affiliates acquires, directly or indirectly, alone or in concert with other Persons, over a period of time or at any one time, shares in the capital stock of Borrower aggregating in excess of 50% of all of the then issued and outstanding common shares and voting securities of Borrower, or if any Person, other than Abraxas Petroleum Corporation or 5 Canadian Abraxas Petroleum Limited or its Affiliates otherwise has the power to direct or cause the direction of the management and policies of Borrower. "Collateral Account" has the meaning set forth in Section 3.4. "Collateral Coverage Default" shall exist at all times when the Collateral Coverage Ratio is less than 125%. "Collateral Coverage Deficiency" shall exist at all times when the Collateral Coverage Ratio is less than 150% but greater than or equal to 125%. "Collateral Coverage Ratio" means, at any time, the ratio, expressed as a percentage, of (i) the sum of (A) Risked NPV10, plus (B) Working Capital, divided by (ii) Lender's Adjusted Investment. "Commitment" means Lender's obligation to make Loans pursuant to Section 2.1. "Commitment Amount" means, on the Effective Date $40,000,000, as such amount may be reduced or increased from time to time pursuant to Section 2.2. "Commitment Termination Date" means the earliest of (i) the Stated Maturity Date, (ii) the date on which the Commitment Amount and the Maximum Commitment Amount are terminated in full or reduced to zero pursuant to Section 2.2, and (iii) the date on which any Commitment Termination Event occurs. Upon the occurrence of any event described in clause (i) or (ii) of this definition, the Commitment shall terminate automatically without further action. "Commitment Termination Event" means (i) the occurrence of any Event of Default described in Section 9.1(h) or 9.1(i), or (ii) the occurrence and continuance of any other Event of Default and either (a) the declaration of the Loans to be due and payable pursuant to Section 9.2 has been made, or (b) in the absence of such declaration, the giving of notice by Lender to Borrower that the Commitment has been terminated pursuant to Section 9.2. "Constating Document" means, relative to Borrower or its Subsidiaries, if any, its certificate of incorporation, formation or organization, its by-laws, operating agreement or other similar agreement and all shareholder agreements, voting trusts and similar arrangements applicable to any of its authorized shares of common stock. "Contingent Liability" means any agreement, undertaking or arrangement by which any Person guarantees, endorses or otherwise becomes or is contingently liable upon (by direct or indirect agreement, contingent or otherwise, to provide funds for payment, to supply funds to, or otherwise to invest in, a debtor, or otherwise to assure a creditor against loss) the Indebtedness of any other Person (other than by endorsements of instruments in the course of collection), or guarantees the payment of dividends or other distributions upon the securities of any other Person. The amount of any Person's obligation under any 6 Contingent Liability shall (subject to any limitation set forth therein) be deemed to be the outstanding principal amount (or maximum principal amount, if larger) of the Indebtedness guaranteed thereby. "Cumulative Return on Total Funding" means the annualized rate of return (on a before tax basis) actually earned by Lender from the repayment of all Indebtedness of Borrower to Lender under and pursuant to any of the Loan Documents, including for greater certainty, obligations of the Borrower arising under the Override, including any return resulting from the unwinding or early termination of a Borrower Hedging Agreement (the "Payout Amount"). "Debenture" means the Debenture executed and delivered pursuant to Section 5.4(a) substantially in the form of Exhibit D-1, as amended, supplemented, restated or otherwise modified from time to time. "Debenture Pledge Agreement" means the Debenture Pledge Agreement executed and delivered pursuant to Section 5.4(a), substantially in the form of Exhibit D-2, as amended, supplemented, restated or otherwise modified from time to time. "Default" means any Event of Default or any condition, occurrence or event which, after notice or lapse of time or both, would constitute an Event of Default. "Default Rate" has the meaning set forth in Section 3.3. "Development Plan" means either (i) the development plan for the 2 year period after the Effective Date delivered to Lender pursuant to Section 5.10 and attached hereto as Exhibit I, or (ii) the updated development plan, as required by and in accordance with Section 7.11, for the 2 year period beginning on the date of delivery in substantially the same form as Exhibit I delivered to Lender and determined to be acceptable by Lender. "Direct Taxes" means (i) ad valorem taxes (or Taxes imposed in lieu thereof) imposed or assessed upon the Subject Interests or any mortgage thereof, (ii) corporate income tax, severance, gross production, occupation, extraction, gathering, and other Taxes and assessments of any kind, including conservation levies (other than (A) Taxes on or measured by Lender's net income or receipts and (B) franchise taxes) imposed or assessed with respect to or measured by or charged against the Subject Interests, and (iii) all other Taxes required by Applicable Law to be deducted from the proceeds of the Subject Interests. "Disbursement Request" has the meaning set forth in Section 3.4(b). "Disclosure Schedule" means the Disclosure Schedule attached as Schedule II, as it may be amended, supplemented or otherwise modified from time to time by Borrower with the written consent of Lender. "Dollar" and the sign "$" mean lawful money of Canada. "Effective Date" means December 20, 2001, or such other date as may be agreed to by the Parties. 7 "Environment" means all components of the earth, including all layers of the atmosphere, air, land (including all underground spaces and cavities and all lands submerged under water), soil, water (including surface and underground water), organic and inorganic matter and living organisms, and the interacting natural systems that include the components referred to in this definition. "Environmental Certificate" means a certificate substantially in the form of Exhibit J. "Environmental Laws" means all Applicable Laws relating to public health and safety and protection of the Environment. "Event of Default" has the meaning set forth in Section 9.1. "Existing Burdens" means, for any period, the aggregate amounts payable in respect of existing royalty, overriding royalty and other cost-free interests as a result of production of Hydrocarbons from the Subject Interests which burdens have been taken into account in determining the working interests and the net revenue interests in the Initial Subject Interests disclosed to Lender on Item 1.1 of the Disclosure Schedule. "GAAP" means generally accepted accounting principles which are in effect from time to time in Canada, in the case of Borrower, and the United States of America, in the case of Abraxas Petroleum Corporation. "Governmental Agency" means any federal, state, provincial, municipal, regional, tribal or local government or governmental department or other entity charged with the regulation, administration, interpretation or enforcement of any Applicable Law. "Hazardous Material" means (i) any "hazardous substance", as defined by the Environmental Protection and Enhancement Act (Alberta), as amended, or any similar legislation in jurisdictions where Borrower currently or in the future owns Property, (ii) any "hazardous waste", as defined by the Environmental Protection and Enhancement Act (Alberta), or any similar legislation in jurisdictions where Borrower currently or in the future owns Property, (iii) any petroleum product, or (iv) any pollutant or contaminant or hazardous, dangerous or toxic chemical, material or substance within the meaning of any other applicable Environmental Law relating to or imposing liability or standards of conduct concerning any hazardous, toxic or dangerous waste, substance or material, all as amended or hereafter amended. "Hedging Agreement" means any swap agreement, hedge agreement, floor agreement, collar agreement or other similar arrangement or agreement, including, any such agreement entered into in connection with an ISDA Master Agreement. "Hedging Obligations" means, with respect to any Person, all liabilities of such Person under Hedging Agreements, and all other agreements or arrangements designed to protect such Person against fluctuations in interest rates, commodity prices or currency exchange rates. 8 "herein", "hereof", "hereto", "hereunder" and similar terms contained in this Agreement or any other Loan Document refer to this Agreement or such other Loan Document, as the case may be, as a whole and not to any particular Section, paragraph or provision of this Agreement or such other Loan Document. "Hydrocarbon Proceeds" means the sum of all revenues and proceeds (i) received by Borrower from the sale of Hydrocarbons attributable to the Subject Interests and (ii) received (or if paid, less such amount) by Borrower from the settlement of any Hedging Agreement. Adjustments under clause (i) above will include adjustments related to third parties only, to be determined by Lender in its discretion acting reasonably, for (A) processing, treating and marketing fees, (B) fuel, shrinkage and unaccounted for losses, (C) fractionation costs, (D) storage and loading costs, (E) transportation costs including pipeline tariff, pipeline losses, and truck transport, and (F) any freight differentials received or allowed. "Hydrocarbons" means, collectively, oil, condensate and other liquid hydrocarbons, including natural gas or liquid products extracted from gas by means other than conventional field separation, and natural gas, casinghead gas, and other gaseous hydrocarbons, and, if applicable, helium and sulphur. "including" means including without limiting the generality of any description preceding such term. "Indebtedness" of any Person means, without duplication: (i) all obligations of such Person for borrowed money and all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments, (ii) all obligations, contingent or otherwise, relative to the face amount of all letters of credit, whether or not drawn, and banker's acceptances issued for the account of such Person, (iii) all obligations of such Person as lessee under leases which have been or should be, in accordance with GAAP, recorded as Capitalized Lease Liabilities; (iv) all other items which, in accordance with GAAP, would be included as liabilities on the liability side of the balance sheet of such Person as of the date at which Indebtedness is to be determined, (v) net liabilities of such Person under all Hedging Obligations, (vi) whether or not so included as liabilities in accordance with GAAP, all obligations of such Person to pay the deferred purchase price of Property or services, and indebtedness (excluding prepaid interest thereon) secured by a Lien on Property owned or being purchased by such Person (including indebtedness arising under conditional sales or other title retention agreements), whether or not such indebtedness shall have been assumed by such Person or is limited in recourse, and (vii) all Contingent Liabilities of such Person in respect of any of the foregoing. For all purposes of this Agreement, the Indebtedness of any Person shall include the Indebtedness of any partnership in which such Person is a general partner and Indebtedness of a joint venture attributable to any such Person under any joint venture agreement or Applicable Law. "Indemnified Liabilities" has the meaning set forth in Section 12.4. "Indemnified Parties" has the meaning set forth in Section 12.4. 9 "Independent Reserve Report" has the meaning set forth in Section 7.3(n). "Initial Drilling Program" means the well drilling program for the 42 initial wells on the Subject Interests which is completed in accordance with the Development Plan. "Initial Hedging Agreement" has the meaning set forth in Section 7.17. "Initial Subject Interests" means all the right, title and interest of Borrower and its Subsidiaries in the initial Subject Properties, and are more particularly described in Schedule I. "Interest Rate" means, on any date and with respect to the Loans, a fixed rate of interest equal to 9.5% per annum (based on a year of 365 days), subject to the adjustments as set forth herein. "Internal Reserve Report" has the meaning set forth in Section 7.3(o). "ISDA Master Agreement" means the International Swaps and Derivatives Association, Inc. Master Agreement executed and delivered pursuant to Section 5.20, substantially in the form of Exhibit H, as amended, supplemented, restated or otherwise modified from time to time. "Joint Operating Agreement" means all operating agreements to which Borrower is a party and which govern the operation of the Subject Interests, as each may be amended, supplemented, restated or otherwise modified from time to time. "Knowledge" means, with respect to any Person, either (i) the actual knowledge of information by such Person after reasonable inquiry or (ii) any information of which a reasonable and prudent Person operating in the same business capacity should have had knowledge after reasonable inquiry. "Lease Use Hydrocarbons" means any Hydrocarbons which are lost in the production thereof or used by the operator of the Subject Interests or any other Person for the purpose of reinjecting, producing, processing, treating, gathering or transporting Hydrocarbons from the Subject Interests, but only to the extent such Hydrocarbons are so used. "Lender" means Mirant Canada Energy Capital, Ltd., and its successors and assigns. "Lender's Adjusted Investment" means, at any time, the sum of: (i) the then outstanding principal balance of the Loans under this Agreement, plus (ii) any accrued and unpaid interest under the Loan Documents, plus (iii) only to the extent that proceeds have been deposited in the Collateral Account, any accrued and unpaid Override, plus (iv) any unpaid Reimbursable Expenses of Lender which are more than 15 days past due, plus (v) the aggregate amount of royalties that remain unpaid for 30 days beyond the terms contained in the applicable Oil and Gas Leases and for which no designated cash reserves exists, plus (vi) the amount by which (A) the sum of capital expenditures and drilling, workover and 10 recompletion accounts payable of Borrower aggregating $100,000 or more exceeds (B) cash on hand either in the Collateral Account or held by Borrower that is solely earmarked and dedicated to the prompt payment of such costs and expenses. "Lien" means any security interest, mortgage, pledge, hypothecation, assignment, deposit arrangement, encumbrance, lien (statutory or otherwise), charge (whether fixed or floating) against, title retention agreement in respect of or interest in property to secure payment of a debt or performance of an obligation or other priority or preferential arrangement of any kind or nature whatsoever. "Loan" has the meaning set forth in Section 2.1. "Loan Document" means this Agreement, the Debenture, the Debenture Pledge Agreement, the Override Royalty Agreements, the Borrower Hedging Agreements and the ISDA Master Agreement, together with all exhibits, certificates, schedules and attachments thereto, and all other agreements, documents, certificates, financing statements and instruments from time to time executed and delivered pursuant to or in connection with any of the foregoing. "Loan Obligations" means all obligations (monetary or otherwise) of Borrower and each other Person (other than Lender) arising under or in connection with this Agreement and each other Loan Document that terminate upon the Indebtedness incurred pursuant to the Loans being unconditionally and irrevocably paid in full. "Loan Request" means a loan request and certificate duly executed by an Authorized Officer of Borrower, substantially in the form of Exhibit "A". "Maximum Commitment Amount" means, on any date, $150,000,000, as such amount may be reduced from time to time pursuant to Section 2.2. "Net Cash Flow" means, for any period, the sum of: (i) Hydrocarbon Proceeds received by Borrower for such period and any other gross revenues of Borrower (excluding cash flow from the sale of any or all of the Subject Interests or the refinancing of the Loans), minus (ii) Direct Taxes for such period, minus (iii) Existing Burdens for such period, only to the extent that they have been included within the amount of Hydrocarbon Proceeds, minus (iv) Cash Flow from Override for such period, minus (v) interest on the outstanding Loans accrued at the Interest Rate during such period, minus (vi) all Obligations under the Loan Documents related to the enforcement and maintenance of the Loan Documents, including Reimbursable Expenses, minus (vii) Approved Lease Operating Expenses actually paid by Borrower for such period, minus (viii) Approved Third-Party Transportation, Gathering and Marketing Expenses actually paid by Borrower for such period, minus (ix) Approved Capital Expenditures actually paid by Borrower for such period, minus (x) Approved G&A Expenses, minus (xi) goods and services Tax, minus (xii) distributions permitted under Section 8.5, (xiii) minus, a cash reserve of less than or equal to $100,000 to be used for general corporate purposes as the Borrower sees fit from time to time, minus (xiv) any other amounts approved by Lender in its sole and absolute discretion. 11 "Net Sales Proceeds" means the gross cash proceeds net of adjustments from the sale by Borrower of any of the Subject Interests, less the sum of the following expenses incurred in connection with such sale: normal and customary closing-related costs and expenses payable to unaffiliated third parties, such as Taxes (including ordinary and capital obligations incurred by Borrower attributable to such sale), escrow charges, title examination fees, reasonable legal fees and expenses incurred in connection with the sale, reasonable and customary brokerage commissions to third-parties and recording expenses (specifically excluding, however, any payments, commissions, fees or other amounts paid or payable to Borrower or any of its Affiliates or any other Obligor) payable in connection therewith by Borrower or any of its Affiliates as the seller thereunder. "Non-Consent Hydrocarbons" means those Hydrocarbons produced from a well during the applicable period of recoupment or reimbursement pursuant to a non-consent provision covering the relevant well or wells, which Hydrocarbons have been relinquished to the consenting party or participating party under the terms of such non-consent provision as the result of the election by Borrower not to participate in the particular operation. "Obligations" means all Loan Obligations and all other on-going obligations (monetary or otherwise) of Borrower and each other Person (other than Lender) arising under or in connection with the Loan Documents (including the Override Royalty Agreement and pursuant to Section 12.4 and 12.5). "Obligor" means Borrower or any other Person (other than Lender) obligated under any Loan Document. "Oil and Gas Leases" means all oil, gas, mineral and other leases and includes any subleases and assignments of operating rights. "Override" means an overriding royalty interest burdening and carved out of the Subject Interests granted pursuant to the Override Royalty Agreements. "Override Royalty Agreements" means, collectively, Override Royalty Agreement No. 1 and Override Royalty Agreement No. 2. "Override Royalty Agreement No. 1" means the Overriding Royalty Agreement executed and delivered pursuant to Section 5.3(a), substantially in the form of Exhibit "D", as it may be amended, supplemented, restated or otherwise modified from time to time. "Override Royalty Agreement No. 2" means the Override Royalty Agreement executed and delivered pursuant to Section 5.3(b), substantially in the form of Exhibit "E", as it may be amended, supplemented, restated or otherwise modified from time to time. "Override Hydrocarbons" means the Hydrocarbons conveyed to Lender pursuant to each Override Royalty Agreement. "Participant" has the meaning set forth in Section 12.15. 12 "Parties" means the parties to this Agreement, and "Party" means any one of them. "Payment Date" means the fifth (5th) Business Day following the end of each calendar month (commencing February 7, 2002) or, if any such day is not a Business Day, the next succeeding Business Day. "Payout Amount" has the meaning set forth in the definition of "Cumulative Return on Total Funding". "Permitted Liens" means (i) Liens for Taxes, assessments or other governmental charges or levies which are not delinquent or which are being contested diligently in good faith, (ii) Liens in connection with workers' compensation, unemployment insurance or other social security, pension plan or public liability obligations which are not delinquent or which are being contested diligently in good faith, (iii) operators', vendors', carriers', warehousemen's, repairmen's, builder's, mechanics', suppliers', workers', materialmen's, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of oil and gas Properties or statutory landlord's Liens, including lessee or operator obligations under Applicable Law related to the ownership, exploration and production of oil, gas and minerals on private or Crown lands or waters, each of which is in respect of obligations that have not been outstanding more than 90 days or which are being contested diligently in good faith, provided the Persons entitled to the benefits of such Liens are not exercising remedies in respect thereof other than the making of demands or the giving or filing of notices required to perfect such Liens and are not suing for payment of the amounts secured thereby, (iv) Liens which (A) arise in the ordinary course of business under the Joint Operating Agreements, other operating agreements, gas balancing agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreement, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements which are usual and customary in the oil and gas business, and (B) are for claims which either are not delinquent or which are being contested diligently in good faith, provided the Persons entitled to the benefits of such Liens are not exercising remedies in respect thereof other than the making of demands or the giving or filing of notices required to perfect such Liens, (v) Liens reserved in oil and gas mineral leases, agreements or created by statute, to secure royalty, net profits interests, bonus payments, rental payments or other payments out of or with respect to the production, transportation or processing of Hydrocarbons, which are in existence on the Effective Date or the date the Subject Interests are made subject to this Agreement, and which are reflected in Schedule I, (vi) Liens arising solely by virtue of any statutory or common law provision relating to banker's liens, rights of set-off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, (vii) defects or 13 irregularities in title, and liens, charges or encumbrances, which are not such as to interfere materially with the development, operation or value of the Subject Interests and not such as materially to impair title thereto, (viii) encumbrances (other than to secure the payment of Indebtedness or the deferred purchase price of Property or services), easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any property of Borrower for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil, coal or other minerals or timber, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, and defects, irregularities, zoning restrictions and deficiencies in title of any Property which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by Borrower if any, or materially impair the value of such Property subject thereto; (ix) Liens on cash or securities pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business, (x) those Liens consented to in writing by Lender, (xi) Liens securing payment of the Obligations granted pursuant to any Loan Document, (xii) Liens permitted by any other Loan Document, and (xiii) any Liens described on Item 1.1 ("Liens") of the Disclosure Schedule. "Person" means any natural person, corporation, partnership, company, firm, association, trust, Governmental Agency or any other entity, whether acting in an individual, fiduciary or other capacity. "Possible Reserves" means those Hydrocarbon reserves that are not Proved Reserves and are speculative reserves estimated beyond Proved and Probable Reserves where geological and engineering data suggest the presence of additional reserves, but where the risk is relatively high. "Probable Reserves" means those Hydrocarbons reserves which are not Proved Reserves and which analysis of geological and engineering data suggests are more likely than not to be recoverable, but where some element of risk or insufficient data prevent classification as proved. "Production Sale Contracts" means contracts for the sale of Subject Hydrocarbons now in effect or hereafter entered into by Borrower with Lender's written consent. "Projected Income and Expense Attributable to the Subject Interests" means, with respect to the Subject Interests for any period, the sum of: (i) estimated future Net Cash Flow, discounted at 10% per annum, attributable to total Acceptable Proved Reserves for such period, minus (ii) estimated Direct Taxes for such period, minus (iii) estimated Existing Burdens for such period, including the overriding royalties granted pursuant to the Overriding Royalty Agreements, minus (iv) estimated Approved Lease Operating Expenses (which must reflect actual historical results for such period, minus (v) estimated Approved Third Party Transportation, Gathering and Marketing Expenses for such period, minus (vi) estimated Approved Capital Expenditures for such period, including, any anticipated plugging and abandoning costs. In connection with such calculation, pricing assumptions are net at the wellhead and 14 are based on, (A) for volumes of oil and gas swapped or hedged with investment grade counter parties, the hedged price, and (B) for all other volumes, the forward New York Mercantile Exchange contract prices for oil and gas, less the basis adjustments for geographical and quality differentials. If a dispute arises concerning the inclusion of the Approved Lease Operating Expenses relating to workovers or other remedial capital expenses, Approved Independent Engineer will make a good faith determination if such are a predictable, prudent and ongoing expense(s) of Borrower, viewed as a whole (if the Approved Independent Engineer makes such good faith determination, then those expenses previously projected as "capital expenditures" will be included in Approved Lease Operating Expenses). All variables used to determine the Projected Income and Expense Attributable to Subject Interest shall be selected by Lender in its reasonable discretion. "Property" means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible. "Proposed Non-Subject Interest Undertaking" has the meaning set forth in Section 4.4. "Proposed Undertaking" has the meaning set forth in Section 4.3. "Proved Developed Non-Producing Reserves" means (i) those Proved Reserves expected to be produced from existing completion intervals in existing wells for which capacity is planned or available pursuant to an approved Development Plan, but due to pending pipeline connections or other mechanical or contractual requirements Hydrocarbon sales have not yet commenced, and (ii) other non-producing Proved Reserves which exist behind the casing of existing wells, or at minor depths below the present bottom of such wells, which are expected to be produced through these wells in the predictable future, where the cost of making such Hydrocarbons available for production should be relatively small compared to the cost of a new well and for which capacity is planned or available pursuant to an approved Development Plan. "Proved Developed Producing Reserves" means those Proved Reserves which are recoverable from existing completion intervals in existing wells currently open and producing to market at the time of the estimate. "Proved Reserves" means those recoverable Hydrocarbons which have been proved to a high degree of certainty by reason of existing production, adequate testing, or in certain cases by adequate core data and other engineering and geologic information on zones which are present in existing wells or in known reservoirs which are recoverable under existing economic and operating conditions. Reserves that can be produced economically through the application of established improved recovery techniques are included in the proved classification when (i) successful testing by a pilot project or the operation of any installed program in that reservoir or one in the immediate area with similar rock and fluid properties provides support for the engineering analysis on which the project or program was based, and (ii) it is reasonably certain the project will proceed. Reserves to be recovered by improved recovery techniques that have yet to be established through repeated economically successful applications are included in the proved 15 category only after successful testing by a pilot project or after the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including (A) pressure maintenance, (B) cycling, and (C) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. "Proved Undeveloped Reserves" means those Proved Reserves which are expected to be recovered from (i) new wells on undrilled acreage, (ii) the deepening of existing wells where a relatively major expenditure is required for completion, or (iii) an existing well where a relatively large expenditure is required to recomplete an existing completion interval or install production or transportation facilities for a primary or improved recovery project. Proved Undeveloped Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. "Proven Reserves" means, collectively, Proved Reserves, Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves, and Proved Undeveloped Reserves. "Refinancing Date" has the meaning set forth to it in Section 3.2. "Refinancing Period" means the period commencing on the Effective Date and ending at 6:00 p.m. (Calgary, Alberta) on June 20, 2002. "Refinancing Minimum Return" means an amount equal to (i) an amount expressed in Dollars which is a Cumulative Return on Total Funding of 17.5%, plus (ii) an amount equal to the present value (discounted at the rate of 10% per annum) of the Override Royalty Agreement No. 1 attributable to the Subject Properties (other than the Proved Developed Producing Reserves) which are included in the Development Plan in effect on the Refinancing Date (the "PV10"). The PV10 will be calculated as follows: (a) the reserve volumes will be the un-risked reserve volumes, operating expenses, taxes and other burdens, as calculated by Lender based on the Development Plan then in effect, provided that Lender may adjust reserve volumes of certain wells that are subject to the said Development Plan based on performance of wells previously completed as part of the Development Plan between the Effective Date and the Refinancing Date; and (b) the applicable commodity prices will be the NYMEX forward oil and gas price forecasts utilized by Lender at the time of the Refinancing Date adjusted to take into account actual processing, treating and other adjustments, plus the applicable forward basis differentials applicable to the pricing points provided by Lender to Borrower at the time of the Refinancing Date. 16 "Reimbursable Expenses" means all expenses paid or incurred by Lender which consist of, or are incidental to (i) any production-related expense or production-related tax reasonably incurred by Lender in paying or performing any obligations on behalf of Borrower under any of the Loan Documents, (ii) any costs, expenses or other amounts reasonably incurred by Lender in paying or performing any obligations on behalf of Borrower under any of the Loan Documents, (iii) costs associated with cancellation of Borrower Hedging Agreements with Lender or any Affiliate of Lender, including brokers fees, exchange expenses, document expenses and related charges incurred by Lender as a result of contracts entered into during the term of this Agreement, (iv) the Indemnified Liabilities that become owing to any Indemnified Party under this Agreement which have not previously been paid by Borrower, and (v) the Tax Amount. "Release" means to release, spill, leak, pump, pour, emit, empty, discharge, migrate, inject, escape, leach, dispose, dump, abandon, deposit, seep, throw, place, exhaust, inoculate, inject, spray or to do a similar act. "Residual Hydrocarbons" means for any period of time the volume of all Hydrocarbons produced from the Subject Interests other than Override Hydrocarbons during the same period of time. "Risked NPV10" means, at any time, the calculation by Lender, in its sole and absolute discretion, using Lender's customary standards for evaluating reserves, of the present value of future cash flows (discounted at a nominal rate of ten percent (10%) per annum) from the Subject Interests, net of Existing Burdens, based upon the most recent Independent Reserve Report using Lender's customary standards for commodity prices, reserve risking, well and reserves concentration risk and limitations and Proved Developed Producing Reserves immaturity adjustment and which is adjusted from the date of the most recent Independent Reserve Report to the determination date for such calculation. In determining Risked NPV10, Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves, Proved Undeveloped Reserves and Probable Reserves shall include only those reserves for which (i) capital improvements (as reflected in the most recent Independent Reserve Report) have been scheduled and which are reasonably expected to be available from either Lender or Net Cash Flow, as approved by Lender, and (ii) equipment and services are reasonably expected to be available. "Scheduled Payment" means, for any period, an amount equal to the greater of (i) the unpaid and accrued interest on the aggregate unpaid principal amount of the Loans or (ii) Net Cash Flow. "Stated Maturity Date" means December 20, 2007. "Subject Hydrocarbons" means all Hydrocarbons in and under, and which may be produced and saved from, and which shall accrue or be attributable to the Subject Interests and which are produced after the Effective Date (other than Lease Use Hydrocarbons and Non-Consent Hydrocarbons where Borrower is the non-consenting party) and shall be deemed to include the proceeds of such Hydrocarbons. 17 "Subject Interests" means all right, title and interest of Borrower in and to the Subject Properties and the Initial Subject Interests. The term "Subject Interest", when used with reference to any particular Subject Interest, shall mean and include (i) such Subject Interest as the same may be enlarged or diminished by the provisions of any contract or other instrument described in Schedule I, or by the removal of any charges or encumbrances to which such Subject Interest is subject, (ii) any and all renewals, replacements and extensions of such Subject Interest, or other interests in the Hydrocarbons in, under and that may be produced from lands comprising a portion of the Subject Interests acquired by Borrower during the term hereof, (iii) all contracts supplemental to or amendatory of or in substitution for the contracts described above insofar as the same relate to such Subject Interest, and (iv) all rights, titles and interests accruing or attributable to such Subject Interest by virtue of its being included in any pooling or unit. "Subject Property" and "Subject Properties" means the (i) initial Subject Properties more particularly described in Schedule I, and (ii) any and all Oil and Gas Leases and leasehold working interests, net profits interests and production payments, including the Oil and Gas Leases and leasehold working interests, net profits interests, royalty interests, mineral interests and production payments described in Schedule I, together with all Hydrocarbons severed while Obligations continue to exist which are attributable to such leases and interests together with all of the valid Subject Hydrocarbons unitization and pooling agreements which are described in such Schedule I or which relate to any of the properties and interests described in such Schedule I, and (iii) all Properties in which Borrower acquires or purports to acquire an interest in any Acquisition, if any, to the extent such Acquisition is funded by Lender pursuant to the terms of this Agreement. "Subsidiary" means, with respect to any Person, (i) any corporation of which more than 50% of the outstanding capital stock having ordinary voting power to elect a majority of the board of directors of such corporation (irrespective of whether at the time capital stock of any other class or classes of such corporation shall or might have voting power upon the occurrence of any contingency) is at the time directly or indirectly owned by such Person, by such Person and one or more other Subsidiaries of such Person, or by one or more other Subsidiaries of such Person; (ii) any partnership of which such Person, such Person and one or more other Subsidiaries of such Person, or one or more other Subsidiaries of such Person is a general partner, (iii) any limited liability company in which such Person, such Person and one or more other Subsidiaries of such Person, or one or more other Subsidiaries of such Person is a member or manager with ownership interest in excess of 50% of all outstanding ownership interests, or (iv) any other entity in which such Person, such Person and one or more other Subsidiaries of such Person, or one or more other Subsidiaries of such Person has an ownership interest in excess of 50% of all outstanding ownership interests. "Tax Amount" means an amount equal to the aggregate of all amounts, including interest and penalties, if any, relating thereto, paid by Lender in such month, and which have not been paid by Borrower pursuant to the provisions of this Agreement, on account of (i) Direct Taxes, (ii) any excise tax imposed on or assessed with respect to or measured by or charged against the Subject Hydrocarbons, or (iii) any sales or 18 gross receipts taxes, which are imposed on Lender by any Governmental Agency in which any of the Subject Interests are located, and which are payable on account of Lender's Liens in the Subject Hydrocarbons, provided, however, that the Tax Amount shall not include any taxes associated with the handling, transportation, refining, purchase or sale of Subject Hydrocarbons after they have been delivered to the credit of Lender, nor any taxes which are imposed on Lender pursuant to the Income Tax Act (Canada). "Title Certificate" means a certificate substantially in the form of Exhibit I. "Transportation Agreements" means any contract or agreement entered into from time to time by Borrower relating to the transportation of Hydrocarbons, as any such agreement or contract may be amended, supplemented, restated or otherwise modified from time to time. "Working Capital" means, at any time and determined in accordance with GAAP, the excess of (i) consolidated current assets of Borrower, minus (ii) consolidated current liabilities of Borrower. 1.2 Use of Defined Terms. Unless otherwise defined or the context otherwise requires, terms for which meanings are provided in this Agreement shall have such meanings when used in the Disclosure Schedule and in each Loan Request, Loan Document, notice and other communication delivered from time to time in connection with this Agreement or any other Loan Document. 1.3 Cross-References. Unless otherwise specified, references in this Agreement and in each other Loan Document to any Recital, Article or Section are references to such Recital, Article or Section of this Agreement or such other Loan Document, as the case may be, and, unless otherwise specified, references in any Recital, Article, Section or definition to any clause are references to such clause of such Recital, Article, Section or definition. 1.4 Accounting and Financial Determinations. Unless otherwise specified, all accounting terms used herein or in any other Loan Document shall be interpreted, all accounting determinations and computations hereunder or thereunder shall be made, and all financial statements required to be delivered hereunder or thereunder shall be prepared in accordance with GAAP, consistently applied, which were applied in the preparation of the financial statements referred to in Section 6.6. 1.5 Statutes, Regulations and Rules. Any reference in the Loan Documents to all or any section or paragraph or any other subdivision of any Applicable Law will, unless otherwise expressly stated, be a reference to that Applicable Law or the relevant section or paragraph or other subdivision thereof, as such Applicable Law may be amended, substituted, replaced or re-enacted from time to time. 1.6 Monetary References. Whenever an amount of money is referred to in the Loan Documents, such amount will, unless otherwise expressly stated, be in Canadian Dollars. 19 1.7 Schedules and Exhibits. The following are the Schedules and Exhibits which form part of this Agreement: Schedule I - Description of Subject Interests Schedule II - Use of Proceeds Schedule III - Insurance Requirements Schedule IV - Disclosure Schedule Schedule V - Pension Plans Schedule VI - List of Transportation Agreement and Joint Operating Agreements Schedule VII - Financing Lease Arrangements Schedule VIII - Title Deficiencies Exhibit A - Form of Loan Request Exhibit B - Form of Opinion of Borrower's Counsel Exhibit C-1 - Form of Debenture Exhibit C-2 - Form of Debenture Pledge Agreement Exhibit D - Form of Override Royalty Agreement No. 1 Exhibit E - Form of Overriding Royalty Agreement No. 2 Exhibit F - Form of ISDA Master Agreement Exhibit G - Development Plan Exhibit H - Form of Environmental Certificate Exhibit I - Form of Title Certificate Article 2 COMMITMENT AND LOAN PROCEDURES 2.1 Commitment. From time to time on any Business Day occurring prior to the Commitment Termination Date on the terms and subject to the conditions of this Agreement upon delivery of a Loan Request by Borrower to Lender, Lender, in its sole and absolute discretion, may make loans (the "Loans") to Borrower equal to the aggregate amount of the Loan requested by Borrower to be made on such day; provided, however, that if no Default or Event of Default has occurred and is continuing, Lender agrees to make Loans in the amount requested by Borrower to be made on such date in the aggregate amount for all Loans up to the Commitment Amount. The commitment of Lender described in this Section 2.1 is herein referred to as its "Commitment". Lender shall not be required to make any Loan if, after giving effect thereto, the aggregate outstanding principal amount of all Loans would exceed the Commitment Amount. Borrower may not borrow, repay and reborrow Loans. 2.2 Maximum Commitment Amount and Commitment Amount The Maximum Commitment Amount is subject to reduction from time to time pursuant to this Section 2.2. The Commitment Amount is subject to increase or reduction from time to time pursuant to this Section 2.2. (a) Optional Increase or Reduction: ------------------------------- 20 (i) Borrower may, from time to time on any Business Day after December 20, 2002, voluntarily reduce the Commitment Amount and/or the Maximum Commitment Amount; provided, however, that all such reductions shall require at least 3 Business Days' prior notice to Lender and be permanent, and any partial reduction of either the Commitment Amount or the Maximum Commitment Amount shall be in a minimum amount of $500,000 and in an integral multiple of $100,000. (ii) Lender, in its sole and absolute discretion, may, from time to time after giving Borrower 30 days prior written notice, increase or reduce the Commitment Amount; provided, however, that there shall be no reductions in the Commitment Amount if such amount is a contemplated expenditure pursuant to an approved Development Plan; provided, further, that the Commitment Amount may never exceed the Maximum Commitment Amount and, if as a result of a reduction in the Maximum Commitment Amount the Commitment Amount exceeds the Maximum Commitment Amount at any time, the Commitment Amount shall automatically be reduced to an amount equal to the Maximum Commitment Amount; and provided further, that the Commitment Amount may never be reduced to an amount which is less than the amount of outstanding Loans. (b) Mandatory Reduction. Notwithstanding any other provision of the Loan Documents to the contrary, the Commitment Amount and the Maximum Commitment Amount each shall, without any further action, automatically and permanently be reduced to zero ($0) on the Commitment Termination Date. 2.3 Loan Procedure. By delivering a Loan Request to Lender on or before 11:00 a.m., Calgary, Alberta time, on a Business Day, Borrower may from time to time irrevocably request, on not less than 3 nor more than 5 Business Days' notice, that a Loan be made in a minimum amount of $100,000, and in an integral multiple of $100,000 or in the unused amount of the Commitment or in such other amount as agreed to by Lender, in its sole discretion. On the terms and subject to the conditions of this Agreement, each Loan shall be made on the Business Day specified in such Loan Request. Lender shall make funds in an amount equal to the requested Loan available to Borrower by wire transfer or account entry to the Collateral Account or, subject to Lender's consent, to such other account specified in the Loan Request, on or before 1:00 p.m., Calgary, Alberta time, on such Business Day. 2.4 Records. The Lender will maintain records, in written or electronic form, evidencing all Loans and all other Indebtedness owing by Borrower to Lender hereunder and under the other Loan Documents. Lender will enter in such records details of all amounts from time to time owing, paid or prepaid by Borrower to it hereunder. The information entered in such records will constitute prima facie evidence of such Loans and Indebtedness of Borrower to Lender hereunder. 21 Article 3 REPAYMENTS, PREPAYMENTS, INTEREST AND FEES 3.1 Repayments and Prepayments (a) Borrower shall unconditionally and irrevocably repay in full the unpaid principal amount of each Loan and unpaid interest on such Loans on the Stated Maturity Date. Prior thereto, Borrower: (i) may, from time to time on any Business Day after December 20, 2002, make a voluntary prepayment, in whole or in part, of the outstanding principal amount of any Loans; provided, however, that all such voluntary prepayments shall require at least 3 but no more than 5 Business Days' prior written notice to Lender, and provided, further, however, that Borrower may make a voluntary prepayment as required by Sections 7.5 and 9.2(a)(iv) at any time; (ii) shall, on the date of any sale of all or a portion of the Subject Interests, make a mandatory prepayment in the amount of the Net Sales Proceeds from such sale of the Subject Interests; (iii) shall, on each Payment Date, unless otherwise consented to by Lender in writing, make a mandatory repayment in the amount of Borrower's Net Cash Flow for the month prior to such Payment Date; (iv) shall, on each date when any reduction in the Commitment Amount or the Maximum Commitment Amount shall become effective, make a mandatory repayment of all Loans equal to the excess, if any, of the aggregate outstanding principal amount of all Loans at such time over the Commitment Amount as so reduced; and (v) shall, immediately upon any acceleration of the Stated Maturity Date of any Loans pursuant to Section 9.2, repay all Loans, unless only a portion of all Loans is so accelerated. (b) Each prepayment of any Loans made pursuant to Section 3.1(a) shall be without premium or penalty. All prepayments received by Lender pursuant hereto shall be applied (i) if received by Lender prior to 12:00 p.m. (noon), Calgary, Alberta time, on a Business Day, immediately on such Business Day and (ii) if received by Lender after 12:00 p.m. (noon), Calgary, Alberta time, on a Business Day, immediately on the first Business Day thereafter as follows: (i) to the payment and satisfaction of all costs and expenses reasonably incurred in connection with the collection of such payments and proceeds; (ii) to the payment of any accrued interest and fees on the Loans pursuant to this Agreement and each other Loan Document; and 22 (iii) to the payment of the outstanding principal under the Loans outstanding hereunder. 3.2 Refinancing. Notwithstanding Section 3.1, if Borrower pays to Lender the Payout Amount at any time during the Refinancing Period (the "Refinancing Date"), then Borrower shall pay to Lender, on or prior to the end of the Refinancing Period, (which amount while outstanding shall be secured by the security granted pursuant to Section 5.4) the Refinancing Minimum Return. If Borrower pays the Payout Amount to Lender during the Refinancing Period, such payment shall be made free of any prepayment penalty which Lender may incur by virtue of the Payout Amount being made. 3.3 Interest Provisions. ------------------- (a) Interest on the outstanding principal amount of Loans shall accrue daily at the Interest Rate. After the date any principal amount of any Loan is due and payable (whether on the Stated Maturity Date, upon acceleration or otherwise), or after an Event of Default, or after any other monetary Obligation of Borrower shall have become due and payable, Borrower shall pay, but only to the extent permitted by Applicable Law, interest (after as well as before judgment) on such amounts at a rate per annum equal to fifteen percent (15%) ("Default Rate"); provided, that once all such amounts and accrued interest thereon are unconditionally and irrevocably paid in full, interest shall accrue at the Interest Rate. (b) Interest accrued on each Loan shall be payable, without duplication, (i) on the Stated Maturity Date therefor, (ii) on the date of any payment or prepayment, in whole or in part, of principal outstanding on such Loan; (iii) on each Payment Date occurring after the Effective Date; and (iv) on that portion of any Loans the Stated Maturity Date of which is accelerated pursuant to Section 9.2, immediately upon such acceleration. Interest accrued on Loans or other monetary Obligations arising under this Agreement or any other Loan Document after the date such amount is due and payable (whether on the Stated Maturity Date, upon acceleration or otherwise) shall be payable upon demand. (c) For the purposes of the Interest Act (Canada) and all other Applicable Law which may hereafter regulate the calculation or computation of interest on borrowed funds, the annual rates of interest and fees applicable to Loans are the rates as determined hereunder multiplied by the actual number of days in a period of one year commencing on the first day of the period for which such interest is payable and divided by 365. 3.4 Collateral Account. ------------------ (a) Borrower shall cause all Hydrocarbon Proceeds to be delivered to an account designated in writing by Lender from time to time (the "Collateral Account") which is to be maintained by 23 Lender and is in all respects satisfactory to Lender. No funds, other than Hydrocarbon Proceeds and amounts from any Loans, will be paid to the Collateral Account. If, however, funds other than Hydrocarbon Proceeds are deposited into the Collateral Account, Lender will pay such other funds to Persons that Borrower directs Lender to pay in writing. Borrower agrees not to open any new Collateral Account or similar account, or take any action to terminate the existing Collateral Account, without the prior written consent of Lender. All Hydrocarbon Proceeds received by Borrower shall be delivered in kind to Lender for deposit into the Collateral Account and Borrower shall not commingle any such proceeds, and shall hold separate and apart from all other property, all such proceeds in express trust for the benefit of Lender until delivery thereof is made to the Collateral Account. (b) No more than 2 times a month, Borrower may request in writing (a "Disbursement Request"), delivered three (3) Business Days prior to the date of any requested disbursement and executed by an Authorized Officer, that Lender reimburse Borrower or disburse directly to Borrower, as appropriate, out of funds in the Collateral Account, (i) Direct Taxes for such period, (ii) Existing Burdens for such period, (iii) Cash Flow from Override for such period (provided that such amounts will be paid directly to Lender), (iv) interest on the Loans accrued at the Interest Rate or, if applicable, the Default Rate during such period, (provided that such amounts will be paid directly to Lender) (v) all Obligations under the Loan Documents related to the enforcement and maintenance of the Loan Documents, (provided that such amounts will be paid directly to Lender) (vi) all unpaid Scheduled Payments, (provided that such amounts will be paid directly to Lender) (vii) Approved Lease Operating Expenses due for such period, provided that if any material Default or any Event of Default has occurred and is continuing, then only Approved Lease Operating Expenses actually paid by Borrower for such period, (viii) Approved Third-Party Transportation, Gathering and Marketing Expenses due for such period, provided that if any material Default or any Event of Default has occurred and is continuing, then only Approved Third-Party Transportation, Gathering and Marketing Expenses actually paid by Borrower for such period, (ix) Approved Capital Expenditures due for such period, provided that if any material Default or any Event of Default has occurred and is continuing, then only Approved Capital Expenditures actually paid by Borrower for such period, (x) Approved G&A Expenses due for such period, provided that if any material Default or any Event of Default has occurred and is continuing, then only Approved G&A Expenses actually paid by Borrower for such period, (xi) goods and services Taxes, (xii) cash reserves at no time exceeding $100,000 to be used by Borrower for general corporate purposes and (xiii) any other amounts approved by Lender in its sole and absolute discretion. Such Disbursement Request shall set forth in detail the calculation of each such item requested to be paid and shall otherwise contain any information required pursuant to this Section 3.4(b). Lender shall be protected in all instances in paying the foregoing amounts based upon such Disbursement Request without any need whatsoever to independently verify such requested amounts. In addition if 24 any material Default or any Event of Default has occurred and is continuing, and notwithstanding the information provided by Borrower, Lender shall have the right (it being hereby agreed that Lender is not obligated to make such payment, is not responsible to Borrower or any other Person for making or failing to make any such payment and is not responsible for seeing to the application of any such payment) to apply any amount, in its sole discretion, from time to time in the Collateral Account to the payment of any of the previously specified payment items in the priority order in which such specified payment items are listed. (c) After receipt of a Disbursement Request meeting the requirements of Section 3.3(b) by Borrower setting forth in reasonable detail the proposed use of such funds and provided that no material Default or Event of Default has occurred and is continuing, Lender shall transfer to an account designated by Borrower on the requested date for such disbursement (which date must be at least three (3) Business Days after receipt by Lender of the Disbursement Request) any or all of the funds in the Collateral Account. Borrower hereby authorizes Lender in Lender's sole discretion, to pay amounts either to Borrower or to the applicable vendors or other payees directly. Upon submission of a Disbursement Request relating to Approved Lease Operating Expenses, Approved Third-Party Transportation, Gathering and Marketing Expenses and Approved Capital Expenditures, and upon Lender's satisfaction, in its sole discretion, that such requested disbursement is to be made in satisfaction of an Approved Lease Operating Expenses, Approved Third-Party Transportation, Gathering and Marketing Expenses or Approved Capital Expenditures or Approved G&A Expenses, and subject to the other provisions hereof and in accordance with Applicable Laws, and provided that no material Default or Event of Default has occurred and is continuing, Lender shall make the disbursement subject to the conditions in this Agreement and the order of priority set forth in the second paragraph of this Section providing that the foregoing shall not be required. Lender shall have no obligation to make any payment from the Collateral Account in respect of any amount provided in this Section to the extent there are not sufficient funds in the Collateral Account to make any such payment. 3.5 Closing Fee.Borrower agrees to pay to Lender on the Effective Date a non-refundable closing fee in an amount equal to $75,000. 3.6 Engineering Fee. For so long as the Commitment is outstanding, Borrower agrees to pay to Lender on January 1 of each calendar year (commencing January 1, 2002) a non-refundable annual engineering fee in an amount equal to $20,000. Article 4 TAXES AND OTHER PROVISIONS 4.1 Payments, Computations, etc. All payments to be made to Lender by Borrower pursuant to this Agreement or any other Loan Document shall be made by Borrower to Lender, without setoff, deduction or counterclaim (except as may be required by Applicable Law), not later than 12:00 p.m., Calgary, Alberta time, on the date due, in same day or immediately available funds, to such account as Lender shall specify 25 from time to time by notice to Borrower. Funds received after that time shall be deemed to have been received by Lender on the next succeeding Business Day. All interest and fees shall be computed on the basis of the actual number of days (including the first day but excluding the last day) occurring during the period for which such interest or fee is payable over a year comprised of 365 days. Whenever any payment to be made shall otherwise be due on a day which is not a Business Day, such payment shall be made on the next succeeding Business Day and such extension of time shall be included in computing interest and fees, if any, in connection with such payment. 4.2 Setoff. In addition to any rights and remedies of Lender provided by Applicable Law, if a Default or an Event of Default has occurred and is continuing or the Obligations have been accelerated, Lender is authorized at any time and from time to time, without prior notice to Borrower, any such notice being waived by Borrower to the fullest extent permitted by Applicable Law, to setoff and apply any and all deposits (general or special, time or demand, provisional or final) at any time held by, and other indebtedness at any time owing by, Lender or any of its Affiliates, including, amounts pursuant to any preferential right to purchase or market Subject Hydrocarbons and any Borrower Hedging Agreements against any and all Obligations owing to Lender and any of its Affiliates, now or hereafter existing, irrespective of whether or not Lender shall have made demand under this Agreement or any Loan Document and although such Obligations may be contingent or unmatured, and, as security for such Obligations, Borrower hereby grants to Lender and any of its Affiliates a continuing security interest in, any and all balances, credits, deposits or moneys of Borrower then or thereafter maintained with Lender. Lender agrees promptly to notify Borrower after any such setoff and application made by Lender; provided, however, that the failure to give such notice shall not affect the validity of such setoff and application. The rights of Lender and its Affiliates under this Section 4.2 are in addition to other rights and remedies (including other rights of setoff under Applicable Law or otherwise) which Lender and its Affiliates may have. 4.3 Right of First Refusal - Proposed Undertakings. This Section 4.3 shall be in full force and effect until the termination of the Commitment under this Agreement and the full and final satisfaction in cash of all outstanding Obligations. (a) In the event that Borrower or any of its Subsidiaries intends to obtain any financing for the purpose of exploring, developing and producing Hydrocarbons from any Property located within the Subject Interests (other than the Initial Drilling Program) which is (i) in conformity with existing field spacing rules, (ii) in compliance with the requirements of Section 8.12, and (iii) which is not given more than a nominal value in the current calculation of the Risked NPV10 (such proposed exploration, development and production undertaking herein called the "Proposed Undertaking") and prior to Borrower, or any such Subsidiary, approaching any other Person with respect to such Proposed Undertaking, Borrower first shall provide Lender with notice of its or its Subsidiary's intent to enter into such Proposed Undertaking, together with information relating to the terms, conditions, feasibility and economics of such Proposed Undertaking, 26 including an outline of the acreage and proposed leases for the Proposed Undertaking, geological and engineering studies and cost estimates, as well as any other information or data which Lender may reasonably request in order for Lender to adequately evaluate whether Lender would be willing to make a Loan to finance such Proposed Undertaking. (b) Lender shall have the option to make a Loan to finance the Proposed Undertaking (the "Additional Development Program Option") which shall be subject to all of the same terms and conditions (including the Cash Flow from Override) as the then current Subject Interests. Lender shall then have a period of no less than 30 days after the delivery of such notice and all such information and data in order to determine whether Lender shall make a Loan to finance, in whole or in part, such Proposed Undertaking and the amount of such Loan. As soon as Lender reaches its decision, but no later than the end of such period, Lender shall inform Borrower or its Subsidiary, as applicable, whether it will participate in such Proposed Undertaking. Lender shall have no obligation to fund any Proposed Undertaking and may choose to fund (or not to fund) any Proposed Undertaking without limiting its Additional Development Program Option with respect to any future Proposed Undertakings. (c) If, and only if, Lender declines to finance such Proposed Undertaking, Borrower or its Subsidiary, as applicable, shall be permitted to approach other Persons with respect to such Proposed Undertaking, provided that the Proposed Undertaking offered to such other Persons be on economic terms substantially similar to those offered to Lender. (d) In the event that another Person is willing to fund such Proposed Undertaking pursuant to economic terms which are not more onerous to Borrower or its Subsidiary, as applicable, than the economic terms offered by Lender for such Proposed Undertaking, then upon delivery of written evidence to Lender, in form and substance acceptable to Lender, in its reasonable discretion, of the funding by such Person of the Proposed Undertaking, Lender shall release its Liens and reconvey its Override on that portion, and only that portion, of the Subject Interests covered by such Proposed Undertaking and permit Borrower or its Subsidiary, as applicable, to commence the Proposed Undertaking. In the event that such Proposed Undertaking is not commenced as set forth in the preceding sentence within a reasonable period of time (not to exceed 180 days from receiving notice under Section 4.3(a) and such reasonable additional period as may be required in order to obtain any required Approval or access to commence the conduct of such operation), then upon fifteen (15) days prior notice from Lender to Borrower and failure to convene the operations by that time, that portion of the Subject Interests covered by such Proposed Undertaking shall immediately be subjected to first priority, perfected Liens (subject to Permitted Liens) in favor of Lender, including amendments to the Debenture as may be required by Lender covering such portion of the Subject Interests covered by the Proposed Undertaking and granting to Lender the Override on such Properties. 27 (e) Borrower acknowledges, and agrees to cause each of its Subsidiaries to acknowledge, that the granting of this right of first refusal was a material condition and consideration for the extension of the Commitment and that Lender would not have extended the Commitment except for the granting of this right of first refusal with respect to Proposed Undertakings. 4.4 Right of First Refusal-Proposed Non-Subject Interest Undertaking. This Section 4.4 shall be in full force and effect until the termination of the Commitment under this Agreement and the full and final satisfaction in cash of all outstanding Loan Obligations. (a) In the event that Borrower or any of its Subsidiaries, if any, intend to obtain any financing for the purpose of acquiring, exploring, developing, producing or marketing Hydrocarbons for any Property not located within the Subject Interests (such proposed undertaking the "Proposed Non-Subject Interest Undertaking") and prior to Borrower or such Subsidiary approaching any other Person with respect to such Proposed Non-Subject Interest Undertaking of Borrower or such Subsidiary first shall provide Lender with notice of its intent to enter into such Proposed Non-Subject Interest Undertaking, together with information relating to the terms, conditions, feasibility and economics of such Proposed Non-Subject Interest Undertaking, including, geological and engineering studies and cost estimates, as well as any other information or data which Lender may reasonably request in order for Lender to adequately evaluate whether Lender would be willing to make a Loan to finance such Proposed Non-Subject Interest Undertaking. (b) Lender shall have an option to make a Loan to finance such Proposed Non-Subject Interest Undertaking. Lender shall then have a period of no less than thirty (30) days after the delivery of such notice and all such information and data in order to determine whether Lender shall make a Loan to finance, in whole or in part, such Proposed Non-Subject Interest Undertaking and the amount of such Loan. Borrower agrees, and agrees to cause each of its Subsidiaries to agree, to enter into good faith negotiations with Lender with respect to mutually agreeable terms and conditions for the financing of such Proposed Non-Subject Interest Undertaking. As soon as Lender reaches its decision, but no later than the end of such period, Lender shall inform Borrower or such Subsidiary whether it chooses to participate in such Proposed Non-Subject Interest Undertaking. Lender shall have no obligation to fund any Proposed Non-Subject Interest Undertaking under this right of first refusal and may choose to fund (or not to fund) any Proposed Non-Subject Interest Undertaking without limiting its right of first refusal with respect to any future Proposed Non-Subject Interest Undertakings. (c) If Lender declines to finance such Proposed Non-Subject Interest Undertaking, Borrower or such Subsidiary shall be permitted to approach other Persons with respect to such Proposed Non-Subject Interest Undertaking. Lender agrees to provide Borrower with no interest letters and releases, in form satisfactory to Lender and Borrower, in respect of such Proposal Non-Subject Interest Undertakings if required. 28 (d) Borrower acknowledges, and agrees to cause each of its Subsidiaries to covenant and acknowledge, that the granting of this right of first refusal was a material condition and consideration for the extension of the Commitment and that Lender would not have extended the Commitment except for the granting of this right of first refusal. 4.5 Use of Proceeds. (a) Borrower shall apply the proceeds of the initial Loan (i) up to $27,000,000 to repay in full existing Indebtedness of Borrower to Canadian Imperial Bank of Commerce howsoever arising, (ii) up to $40,000,000 minus the amount actually drawn to repay Canadian Imperial Bank of Commerce pursuant to clause (i) above for working capital and general corporate purposes, including distributions to Abraxas Petroleum Corporation and (iii) up to $85,000,000 to finance the drilling of wells and related activities such as land, seismic and infrastructure pertaining to existing and newly-acquired Properties as set forth in the Development Plan. (b) Borrower shall apply the proceeds of each Loan after the initial Loan (i) to develop the Subject Interests in accordance with the Development Plan, (ii) for general business purposes and working capital purposes of Borrower consistent with the Development Plan, (iii) to pay costs, fees and expenses associated with the closing of this Agreement, (iv) to pay interest accrued in connection with the Loan Documents, and (v) in accordance with Schedule II. Article 5 CONDITIONS TO LOANS 5.1 Initial Loan. The obligation of Lender to fund any Loan hereunder shall be subject to the prior or concurrent satisfaction of each of the conditions precedent set forth in this Article 5. 5.2 Resolutions, etc. Lender shall have received from Borrower and each of its Subsidiaries, if any, a certificate, dated the date of the initial Loan, of its Secretary or Assistant Secretary, as applicable, as to (i) resolutions of its directors then in full force and effect authorizing the execution, delivery and performance of this Agreement and each other Loan Document to be executed by it; (ii) its Constating Documents, (iii) the incumbency and signatures of those of its officers authorized to act with respect to this Agreement and each other Loan Document executed by it, upon which certificate Lender may conclusively rely until it shall have received a further certificate of one of its officer canceling or amending such prior certificate, and (iv) that Borrower and all of its Subsidiaries, if any, are in compliance with all of the covenants and agreements contained in this Agreement or any other Loan Document. Lender shall have received from Borrower and each of its Subsidiaries, if any, certificates of existence and good standing provided by the appropriate governmental officer in its jurisdiction of incorporation or formation and, in the case of certificates of good standing, in each jurisdiction in which its business is conducted. 29 5.3 Override Royalty Agreement. Lender shall have received counterparts of (a) the Override Royalty Agreement No. 1 dated as of the date hereof, duly executed by Borrower, and (b) the Override Royalty Agreement No. 2 dated as of the date hereof, which shall at all times be subject to Article 10. 5.4 Security. As security for the present and future Indebtedness of Borrower to Lender (and for the purpose of Hedging Obligations, to any Affiliate of Lender), Lender shall have received counterparts of the following documents, each dated as of the date hereof, duly executed by Borrower: (a) a demand Debenture in the amount of $200,000,000 from Borrower, together with a Debenture Pledge Agreement in respect thereof, providing for a first priority Lien in all of Borrower's present and after-acquired Property, a notice of which is to be registered in all appropriate jurisdictions; (b) when requested by Lender such documents and instruments providing a fixed and specific Lien in accordance with the provisions of the this Agreement and the other Loan Documents; and (c) evidence of the completion (or satisfactory arrangements for the completion) of all recordings and filings of the above-noted security documents in such offices in Canada or any province thereof as may be necessary or, in the reasonable opinion of Lender, desirable effectively to create a valid and perfected Lien (subject to Permitted Liens) against the Properties purported to be covered thereby. 5.5 Release and Discharge Lender shall have received executed copies of statements, if any, necessary to release and discharge of all Liens and other rights of any Person, including Canadian Imperial Bank of Commerce, in any Property described in the Debenture (other than Permitted Liens). 5.6 After-Acquired Property. All Property acquired by or on behalf of Borrower or any of its Subsidiaries, if any, after the date of execution of the security documents listed in Section 5.4 which forms part of the Property of Borrower or any of its Subsidiaries, if any, will be subject to the Liens constituted by the security documents listed in Section 5.4 without any further conveyance, mortgage, pledge, charge, assignment or other act on the part of the Parties. 5.7 Memorandum of Purchase Contracts. Lender shall have received any requested memorandum of agreement relating to the purchase of Hydrocarbons attributable to the Subject Interests executed by Borrower, in form and substance satisfactory to Lender in its sole discretion. 5.8 Opinion of Counsel. Lender shall have received an opinion dated the date hereof and addressed to Lender and its counsel from counsel to Borrower, substantially in the form of Exhibit C. 30 5.9 Certified Copy of Farmout Amending Agreement. Lender shall have received a certified copy of an amending agreement dated on or before December 20, 2001 between Borrower and Canadian Abraxas Petroleum Ltd., amending the Farmout Agreement between the same parties dated July 31, 2001, in form and substance satisfactory to Lender. 5.10 Development Plan and Schedules. Lender shall have received (i) a Development Plan covering the Subject Interests in substance acceptable to Lender, (ii) a description of Initial Subject Interests, in form and substance acceptable to Lender in its sole discretion, and (iii) a "Use of Proceeds" schedule, in form and substance acceptable to Lender in its sole discretion. 5.11 Evidence of Insurance. Lender shall have received certificates of insurance satisfactory to it evidencing the existence of all insurance required to be maintained by Borrower and its Subsidiaries, if any, as applicable, by this Agreement and the other Loan Documents, which insurance, in each case, shall list Lender as "additional insured" and "sole loss payee with respect to first party claims" and be satisfactory to Lender in all respects in its sole discretion. The deductible of each such insurance policy shall be in an amount not to exceed $25,000 per occurrence. 5.12 Approvals. Borrower shall have obtained all necessary Approvals from all Governmental Agencies and from any other Persons relating to the Initial Subject Interests and the related Subject Hydrocarbons or pertaining to the Loan Documents, in form and substance satisfactory to Lender in its sole discretion. Lender shall have received copies of all such Approvals and such Approvals shall be in full force and effect on the Effective Date, and Lender shall have received a certificate to that effect signed by an Authorized Officer of Borrower. 5.13 Compliance with Loan Documents. Borrower shall have performed all agreements and covenants required by this Agreement and by the other Loan Documents to be performed by Borrower, and all representations and warranties herein and in the other Loan Documents made by Borrower, or any other Obligor shall be true and correct as of the Effective Date, and Lender shall have received a certificate to that effect signed by an Authorized Officer of Borrower. 5.14 No Default. No Default or Event of Default shall have occurred and be continuing on the Effective Date either before or after giving effect to this Agreement and the other Loan Documents, and Lender shall have received a certificate to that effect from an Authorized Officer of Borrower. 5.15 Engineering. Lender shall have received an Independent Reserve Report for the Subject Interests dated as of January 1, 2001, in form and substance, and with conclusions, satisfactory to Lender, and, since the date of such report, there has been no material change in respect thereof. Lender also shall have received all requested information regarding the past operating results of the Subject Interests, the current operation of the Subject Interests, Borrower's internal accounting, engineering and production monitoring system, projections of future operating results and the basis for such projections and all 31 other reasonably requested information, all in form, substance and, if applicable, with conclusions, satisfactory to Lender, in its sole discretion. 5.16 Environmental. Lender shall have received an environmental review, including environmental reports (each report to be prepared by a reputable independent consultant acceptable to Lender), relating to all or any part of the Subject Interests, each in form and substance, and with conclusions satisfactory to Lender in its sole discretion, and since the date of such review, there has been no material change in respect thereof. Lender shall have also received an Environmental Certificate. 5.17 Officer's Certificate. Lender shall have received a Title Certificate. 5.18 Release of Liens. Lender shall have received evidence, in form and substance satisfactory to Lender, in its sole discretion, of the release of any and all Liens (other than Permitted Liens) to the extent either (i) filed of record or (ii) Borrower has Knowledge of any such Liens, including, mechanic's liens, materialmen's liens and other similar liens or encumbrances, which encumber the Subject Interests. 5.19 Closing Fees, Expenses, etc. Lender shall have received all fees, costs and expenses due and payable pursuant to Section 3.5 or otherwise and all amounts invoiced pursuant to Section 12.3. 5.20 ISDA Master Agreement. Borrower shall have entered into the ISDA Master Agreement. 5.21 Documents. Lender shall have received a list of each Transportation Agreement to be attached to this Agreement as Schedule VI and Borrower shall provide access to Lender, upon request by Lender, to all other documents evidencing assignment of all Oil and Gas Leases, all right, title and interest in and to the Transportation Agreements, and all other interests represented by Borrower to be part of the Subject Interests. 5.22 Other Legal Matters. All legal matters in connection with the title to the Subject Interests and the Subject Hydrocarbons shall be approved by Lender, and there shall have been furnished to Lender by Borrower at Borrower's expense, such title opinions, agreements, other opinions of counsel, and other records and information, including, evidence of any ratification documents, participation agreements, letter of understanding from any interest owner, as it may reasonably have requested for that purpose, in form and substance satisfactory to Lender, in its sole discretion. 5.23 All Loans. The obligation of Lender to fund any Loan on the occasion of any Loan (including the initial Loan) shall be subject to the satisfaction of each of the conditions precedent set forth in this Section 5.23. (a) Compliance with Warranties, No Default, etc. Both before and after giving effect to any Loan the following statements shall be true and correct: (i) the representations and warranties set forth in Article 6 (excluding, however, those contained in Section 6.8) shall be true and correct with the same effect as if then made (unless stated to relate solely to an earlier 32 date, in which case such representations and warranties shall be true and correct as of such earlier date), (ii) except as disclosed by Borrower to Lender pursuant to Section 6.9 (A) no labor controversy, litigation, arbitration or governmental investigation or proceeding shall be pending or, to the Knowledge of Borrower, threatened against Borrower which might materially adversely affect Borrower's consolidated business, operations, assets, revenues, properties or prospects or which purports to affect the legality, validity or enforceability of this Agreement or any other Loan Document, and (B) no development shall have occurred in any labor controversy, litigation, arbitration or governmental investigation or proceeding disclosed pursuant to Section 6.9 which might materially adversely affect the consolidated businesses, operations, assets, revenues, properties or prospects of Borrower; and (iii) no Default or Event of Default shall have then occurred and be continuing, and the Borrower shall not then be in material violation of any Applicable Law. (b) Loan Request. Lender shall have received a Loan Request for such Loan in accordance with Section 2.3. Each of the delivery of a Loan Request and the acceptance by Borrower of the proceeds of such Loan shall constitute a representation and warranty by Borrower that on the date of such Loan (both immediately before and after giving effect to such Loan and the application of the proceeds thereof) the statements made in Section 5.23(a) are true and correct. A Loan Request, when given by Borrower, will be irrevocable and will oblige Borrower to take the action contemplated herein and therein on the date specified therein. (c) Satisfactory Legal Form. All documents executed or submitted pursuant hereto by or on behalf of Borrower shall be satisfactory in form and substance to Lender; Lender and its counsel shall have received all information, Approvals, opinions, documents or instruments as Lender may reasonably request. Article 6 REPRESENTATIONS AND WARRANTIES 6.1 Representations. In order to induce Lender to enter into this Agreement and to make Loans hereunder, Borrower represents and warrants unto Lender as set forth in this Article 6. 6.2 Organization. Borrower is a corporation validly organized and existing under the laws of the Province of Alberta, is duly qualified to do business and is as an extra-provincial corporation in each jurisdiction where the nature of its business requires such qualification, including British Columbia and the Northwest Territories and has full power and authority and holds all requisite Approvals to enter into and perform its Obligations under this Agreement, and each other Loan Document to which each is a party and to own and hold under lease its property and to conduct its business substantially as currently conducted by it. 33 6.3 Due Authorization, Non-Contravention, etc. Borrower has the full legal power, right and capacity to enter into and perform this Agreement and the other Loan Documents and to sell and convey the Override. Borrower has the full legal power, right and capacity to enter into and perform the Loan Documents. The execution, delivery and performance by Borrower of this Agreement and each other Loan Document executed or to be executed by it are within Borrower's corporate powers, have been duly authorized by all necessary action, and do not (i) contravene Borrower's Constating Documents, (ii) contravene or result in any violation of or default under any Applicable Law or any material contract to which Borrower is a party or any material restriction, court decree or order, in each case binding on or affecting Borrower or any Properties, businesses, assets or revenues of Borrower; or (iii) result in, or require the creation or imposition of, any Lien on (except for the Liens created by the Loan Documents) any of Borrower's Properties, businesses, assets or revenues. 6.4 Government Approval, Regulation, etc. No authorization or Approval or other action by, and no notice to or filing with, any Governmental Agency or other Person is required to be obtained by Borrower for the due execution, delivery or performance by Borrower of this Agreement or any other Loan Document. Borrower does not conduct any business, or derive any revenues from any operations, outside the Provinces of Alberta and British Columbia or the Northwest Territories. Borrower does not have any business related to, or derive any revenue from, the production or marketing of Hydrocarbons outside the Provinces of Alberta and British Columbia or the Northwest Territories. 6.5 Validity, etc. This Agreement and each other Loan Document executed by Borrower constitute, the legal, valid and binding obligations of Borrower enforceable in accordance with their respective terms, in each case subject to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors' rights generally. 6.6 Financial Information. The financial statements of Borrower and Abraxas Petroleum Corporation and any related statements of earnings and cash flow, copies of which have been furnished to Lender, including the information furnished to Lender have been prepared in accordance with GAAP consistently applied, and present fairly the consolidated financial condition of the Persons covered thereby as at the dates thereof and the results of their operations for the periods then ended. 6.7 No Material Adverse Change. Since the date of the financial statements described in Section 6.6, there has been no material adverse change in the financial condition, operations, business, Properties or prospects of either Borrower or its Subsidiaries, taken as a whole. 6.8 Litigation, Labor Controversies, etc. There is no pending or, to the Knowledge of Borrower, threatened litigation, action, proceeding or labor controversy affecting Borrower or any of its Subsidiaries or any of their respective Properties, businesses, assets or revenues, or the Subject Interests, which may materially adversely affect the financial condition, operations, assets, business, properties or prospects of Borrower or such Subsidiary or the Subject Interests or which purports to affect the legality, validity or enforceability of this Agreement or any other Loan Document, except as disclosed in the Disclosure 34 Schedule. 6.9 Subsidiaries. Borrower has no Subsidiaries. 6.10 Borrower's Shares. All of the issued and outstanding shares of Borrower are legally and beneficially directly or indirectly owned by Abraxas Petroleum Corporation. 6.11 Subject Interests. The descriptions attached to Schedule I completely and correctly describe the Subject Interests. The representations and warranties of Borrower in the Override Royalty Agreement are true and correct in all respects as of the dates made or deemed made, and as of the Effective Date, Borrower's ownership of the Subject Interests entitles Borrower and such Subsidiary to a share of all Hydrocarbons produced from or attributable to the Oil and Gas Leases located on or under any of the lands described in Schedule I, and of the proceeds of such production, after giving effect to and/or deducting all applicable royalties, overriding royalties and other burdens or payments out of production (except the Override), which is not less than the respective net revenue interests identified on Schedule I and obligates Borrower to pay a share of all costs of operation and development of such Oil and Gas Leases which is not greater than the respective working interests identified on Schedule I. Borrower has good and marketable title to its Properties (including all Subject Interests) free and clear of all Liens, except for Permitted Liens. The Override Royalty Agreement will assign to Lender good and marketable title to the Override, free and clear of any Lien, except for Permitted Liens. Each lease and other interest in the Subject Interests and the Override is valid and in full force and effect, all ad valorem taxes, rentals, royalties and other amounts in respect thereof which are due, or have become due, have been paid and no default has occurred in respect of any such lease or interest which would have a material adverse effect on the Override. The Subject Interests are not subject to any tax or common law partnership, other than Permitted Liens. Borrower is the legal and beneficial owner of the right, title and interest to the Subject Interests more fully described on Schedule I. 6.12 Oil and Gas Leases. Each Oil and Gas Lease, and other interests described in Schedule I is valid and subsisting and in full force and effect, insofar as it covers or relates to the interests in land referred to or described in Schedule I as covered thereby; all material agreements, contracts, leases, permits, easements, rights-of-way, and other surface use rights necessary to own, maintain and operate such Oil and Gas Leases are in full force and effect and no material breach or default exists under any of such leases, agreements, contracts, permits, easements, rights-of-way or other rights. All rentals, royalties and taxes and other amounts due and payable under or in respect of the Oil and Gas Leases and other interests, or any of them, have been duly paid or provided for. No material default or event of default now exists under any of said leases and other interests and no material breach or default exists thereunder. 6.13 Preferential Rights. Except for: (i) the preferential purchase rights contained in Article 11 and the Override, (ii) the preferential purchase rights contained in the Joint Operating Agreements, and (iii) any preferential rights described in Schedule IV, there are no sale or use contracts or agreements, preferential purchase rights, calls, rights of first refusal or other similar rights or agreements in effect 35 relating to any of the Subject Interests or the properties burdened by the Override. No other Person has any contractual or other rights owed to it by Borrower which would restrict Borrower from honoring its obligations to deliver Hydrocarbons pursuant to the Loan Documents. 6.14 Balancing and Take-or-Pay Contracts. Except under any Joint Operating Agreement, none of the Subject Interests or any of the Subject Hydrocarbons is subject to or encumbered by a balancing, take-or-pay/make-up, deferred production, hydrocarbon banking or other arrangement under which one or more third parties may take a portion of the Subject Hydrocarbons without full payment therefor, in cash or immediately available funds at the market price or value thereof, as a result of Hydrocarbons having been taken from, or as a result of other actions or inactions with respect to, the Subject Interests or other properties. 6.15 Production Requirements. The production of all Hydrocarbons which have heretofore been produced from the Subject Interests is not in excess of allowable production quotas allowed or permitted to the Subject Interests by any applicable Governmental Agency so as to subject, after the Effective Date, any well located thereon, or Lender's interest in the production therefrom, to restrictions or penalties on allowables for overproduction. 6.16 Facilities. All wells, facilities, equipment and other Property of whatever kind or nature that are on the Subject Properties and are used in the operation of the Subject Interests are in good repair and working condition, normal wear and tear excepted, and have been designed, installed, and maintained in accordance with good industry standards and all applicable legal requirements; all wells on the Subject Interests are equipped for production and connected to a gathering system of sufficient capacity and pressure to permit, under ordinary operating conditions, the continuing delivery of Hydrocarbons in volumes equal to the volumes historically delivered; and all wells, facilities, equipment, and other Property of whatever kind or nature on the Subject Interests, together with those wells, facilities, equipment and other Property contemplated in the Development Plan, are, or will be subject to funding hereunder, capable of effecting the Development Plan. The facilities and arrangements by which Borrower disposes, or plans to dispose, of water produced either are sufficient or will be in compliance with the requirements of the Development Plan to dispose of the volumes of water currently, or expected to be, produced from the Subject Interests, and Borrower has no Knowledge or any reason to believe that the facilities and arrangements to be installed pursuant to the Development Plan will not be adequate in the future. 6.17 Broker's Fees. No Broker's Fee is owed by Borrower in respect of the matters provided for in this Agreement or any of the other Loan Documents. 6.18 Taxes. The Borrower has filed all federal, provincial and other tax returns and reports required by Applicable Law to have been filed by it and has paid all Taxes, assessments, fees and other governmental charges thereby shown to be owing, except any such Taxes, assessments, fees or charges which are being diligently contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP shall have been set aside on its books. 36 6.19 Compliance with Laws. The Borrower (i) is not in violation of any Applicable Law of, or the terms of any license or permit issued by, any Governmental Agency, or (ii) has not failed to obtain any license, permit, franchise or other Approval necessary to ownership of any of its Properties or the conduct of its business except where such failure would not reasonably be expected to adversely affect Borrower. 6.20 Environmental Warranties. (i) All of the Subject Interests and associated facilities operated by Borrower has been, and continue to be, owned, leased or operated by Borrower in compliance with all material Environmental Laws; (ii) there have been no past, and there are no pending or, to the Knowledge of Borrower, threatened claims, complaints, notices or inquiries to, or requests for information received by, or known to, Borrower with respect to, any alleged violation of any Environmental Law with respect to the Subject Interests or associated facilities operated by Borrower; (iii) there are no pending or, to the Knowledge of Borrower, threatened claims, complaints, notices or inquiries to, or requests for information received by, or known to Borrower for potential liability under any Environmental Law or under any common law theories relating to operations or the condition of any of the lands comprising the Subject Interests (including underlying groundwater); (iv) to the Knowledge of Borrower, there have been no Releases of Hazardous Materials at, on or under the Subject Property, (v) Borrower has not been issued a notice of non-compliance and are in material compliance with all permits, certificates, approvals, licenses and other authorizations relating to environmental matters and necessary or desirable for its business and the operation of each of the Subject Interests; (vi) to the Knowledge of Borrower, none of the lands comprising the Subject Interests or any portion thereof are listed or proposed for listing on any federal or provincial list of sites requiring investigation or clean-up; (vii) to the Knowledge of Borrower, there are no underground storage tanks, active or abandoned, including petroleum storage tanks, on or under any of the lands comprising the Subject Interests; (viii) to the Knowledge of Borrower, Borrower has not directly transported or directly arranged for the transportation of any Hazardous Material (except crude oil and/or natural gas sold in the ordinary course of business or produced waters which has not created any material liability or obligation of Borrower) to any location which is listed or proposed for listing on any federal or provincial list or which is the subject of federal, provincial or local enforcement actions or other investigations which may lead to material claims against Borrower or any portion of any of the Subject Interests for any remedial work, damage to natural resources or personal injury; (ix) to the Knowledge of Borrower, there are no polychlorinated biphenyls, radioactive materials (other than naturally occurring radioactive material (NORM)) or friable asbestos present at any of the lands comprising the Subject Interests; and (x) to the Knowledge of Borrower, no condition exists at, on, under or in respect of any of the lands comprising the Subject Interests or any portion thereof which, with the passage of time, or the giving of notice or both, would give rise to material liability under any Environmental Law. 6.21 Accuracy of Information. All factual information heretofore or contemporaneously furnished by or on behalf of Borrower or Abraxas Petroleum Corporation in writing or otherwise to Lender for purposes of or in connection with this Agreement or any transaction contemplated hereby, including the Development Plan, the Independent Reserve Report 37 and factual data supporting any reserve reports and financial statements, and any aging of accounts payable and accounts receivable, is, and all other such factual information hereafter furnished by or on behalf of Borrower to Lender will be, true and accurate in every material respect on the date as of which such information is dated or certified and as of the date of execution and delivery of this Agreement by Lender, and such information is not, or shall not be, as the case may be, incomplete by omitting to state any material fact necessary to make such information not misleading. Borrower has no Knowledge of any omission of material fact which renders any such information incomplete or misleading in any way. 6.22 No Prohibition on Perfection. None of the terms or provisions of any indenture, mortgage, deed of trust, agreement or other instrument to which Borrower or any of its Subsidiaries, is a party or by which Borrower or any of its Subsidiaries, or the Property of Borrower or any of its Subsidiaries, is bound prohibit the filing or recordation of any of the Loan Documents or any other action which is necessary or appropriate in connection with the perfection of the Liens evidenced and created by any of the Loan Documents. 6.23 Solvency. Borrower is not "insolvent," as such term is used and defined in the Bankruptcy and Insolvency Act (Canada) or the Companies' Creditors Arrangement Act (Canada). 6.24 Insurance. Borrower has the benefit of the insurance coverage described in the certificates of insurance delivered pursuant to Article 5 and required to be maintained pursuant to Section 7.12. 6.25 No Default. No Default or Event of Default has occurred and is continuing. 6.26 Farmout Lands. To the best of Borrower's Knowledge, information and belief, there are no security registrations made against any of the "Farmout Lands" as described in the Farmout Agreement dated July 31, 2001 between Borrower and Canadian Abraxas Petroleum Limited pursuant to the March 26, 1999 Abraxas Petroleum Corporation Indenture with Norwest Bank Minnesota, N.A. (now Wells Fargo) or the December 21, 1999 Abraxas Petroleum Corporation et al Indenture with Firstar Bank, N.A. (collectively, the "Indentures") or otherwise, and if such registrations have been made, Borrower will cause such registrations to be discharged or to obtain no interest Letters from the Trustees pursuant to the Indentures. Article 7 AFFIRMATIVE COVENANTS 7.1 Affirmative Covenants. Borrower agrees with Lender that, until the unconditional and irrevocable payment in full in cash of all accrued and outstanding monetary Loan Obligations and the termination or expiration of the Commitment, Borrower will perform, or cause each of its Subsidiaries to perform, the obligations set forth in this Article 7. 38 7.2 Punctual Payment Borrower will pay or cause to be paid all Indebtedness and other Obligations payable under the Loan Documents punctually when due. Borrower will also pay or cause to be paid, promptly when due and in any event within 30 days of its payment due date, all accounts payable by Borrower, unless being contested in good faith by Borrower. 7.3 Financial Information, Reports, Notices, etc. Borrower will furnish, or will cause to be furnished, to Lender copies of the following financial statements, reports, notices and information: (a) as soon as available and in any event within 60 days after the end of each of the first three fiscal quarters of each fiscal year of Borrower and Abraxas Petroleum Corporation, unconsolidated balance sheets of Borrower and consolidated balance sheet of Abraxas Petroleum Corporation as of the end of such fiscal quarter and unconsolidated statements of earnings and cash flow of Borrower and consolidated statements of earnings and cash flow of Abraxas Petroleum Corporation for such fiscal quarter and for the period commencing at the end of the previous fiscal year and ending with the end of such fiscal quarter, and any other financial records or reports of Borrower or Abraxas Petroleum Corporation requested by Lender, all prepared in accordance with GAAP, certified by an Authorized Officer of Borrower and Lender, in its reasonable discretion, shall have the right to employ, at Borrower's sole expense, an independent accountant, acceptable to Lender in its sole discretion, to independently verify the accuracy of such financial statements; (b) as soon as available and in any event within 120 days after the end of each fiscal year of Borrower, a copy of the annual audit report for such fiscal year for Borrower and Abraxas Petroleum Corporation, including therein consolidated balance sheets of Abraxas Petroleum Corporation as of the end of such calendar year and consolidated statements of earnings and cash flow of Borrower and its Subsidiaries for such calendar year and a lease operating statement, including oil, gas and water production, average prices received, and lease operating costs, including transportation, gathering and marketing costs, and all expenses on a well-by-well and asset-by-asset basis, and any other financial records or reports of Borrower requested by Lender, all financial statements prepared in accordance with GAAP, in each case certified by the auditors of Abraxas Petroleum Corporation (the "Accountant"), together with a certificate from such Accountant to the effect that, in making the examination necessary for the signing of such annual report by such Accountant, they have not become aware of any Default or Event of Default that has occurred and is continuing, or, if they have become aware of such Default or Event of Default, describing such Default or Event of Default and the steps, if any, being taken to cure it; (c) as soon as available and in any event within 30 days after the end of each calendar month, (i) a monthly cash flow report of Borrower for such month detailing sources and uses of funds, (ii) a monthly compilation and aging of all accounts receivables and accounts payable of Borrower for such month, (iii) a monthly summary of capital expenditures of Borrower 39 since the Effective Date and projections of capital expenditures to be made in the future on a well-by-well and asset-by-asset basis, (iv) a summary of net and gross general and administrative expenses of Borrower for such month, and (v) a lease operating statement for such month, including oil, gas and water production, average prices received, and lease operating costs, including transportation, gathering and marketing costs, and all expenses on a well-by-well and asset-by-asset basis, and any other financial records or reports of Borrower reasonably requested by Lender, all prepared in accordance with GAAP, certified by an Authorized Officer of Borrower; (d) on each Payment Date, a detailed calculation of Net Cash Flow for the preceding three month period; (e) as soon as available and in any event within 45 days after the end of each calendar quarter of each calendar year of Borrower, a summary of Capital Expenditures from the Effective Date, detailed projections of all future Capital Expenditures under the Development Plan, and a comparison of actual Capital Expenditures by Borrower since the Effective Date to Approved Capital Expenditures during the same period, and any other records or reports of Borrower reasonably requested by Lender in connection with Capital Expenditures, all prepared in accordance with GAAP, certified by an Authorized Officer of Borrower; (f) as soon as possible and in any event within three (3) Business Days after the occurrence of each Default or Event of Default, a statement of an Authorized Officer of Borrower setting forth details of such Default or Event of Default and the action which Borrower has taken and/or proposes to take with respect thereto; (g) promptly upon receipt and in any event not later than three (3) Business Days following such receipt, any information concerning any actions, suits or proceedings by or before any court, arbitrator or any Governmental Agency pending, or to the Knowledge of Borrower threatened, against Borrower or any of the Subject Interests, including any foreclosure proceedings, if the aggregate amount of the claims under such actions, suits or proceedings is greater than $50,000; (h) as soon as available, and in any event within 30 days after such reports become available, copies of all interim reserve reports prepared by Borrower or any third-party engineer relating to the Subject Interests; (i) as soon as available, and in any event within 30 days of any filing, copies of all federal income tax filings of Borrower, and any schedules or exhibits attached thereto, certified by an Authorized Officer of Borrower; (j) at such times as may be requested by Lender, reports concerning any change in methods of treatment or operation of all or any wells on Subject Interests and production of Subject Hydrocarbons, any drilling or development, any method of secondary or tertiary recovery, or any other action with respect to the Subject Interests, the decision as to which 40 would reasonably be expected to materially increase or reduce the quantity of Hydrocarbons ultimately recoverable from the Subject Interests, or the rate of production therefrom, or which would reasonably be expected to materially shorten or lengthen the period of time required for amortization of the Loans; (k) as from time to time reasonably requested by Lender, copies of any maps showing property lines and well locations, well logs, core analysis, flow and pressure tests, crude oil and natural gas analysis and casing programs and other technical information related to the Subject Interests and the wells thereon and the production therefrom in the possession, or under the direct or indirect control, of Borrower; (l) together with the delivery of the financial statements delivered pursuant to Sections 7.3(a) and (b), a certificate executed by an Authorized Officer of Borrower certifying that Borrower is in compliance in all material respects with the terms of this Agreement and the other Loan Documents, or if not, specifying any exceptions thereto in reasonable detail; (m) immediately, and in any event by the end of the following Business Day, appropriate daily drilling reports and other information as may be reasonably requested by Lender in connection with the Subject Interests; (n) no later than March 31 of each calendar year, reports in form and substance satisfactory to Lender and using pricing, engineering and other assumptions acceptable to Lender, prepared by the Approved Independent Engineer, effective as of January 1 of such calendar year, concerning (i) the quantity of Subject Hydrocarbons economically recoverable based upon the assumptions provided by Lender from the Subject Interests, including the quantity of Proved Reserves, Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves, Proved Undeveloped Reserves and Probable Reserves; (ii) the Projected Income and Expense Attributable to the Subject Interests; (iii) any change in methods of treatment or operation of all or any wells on Subject Interests, any new drilling or development, any method of secondary or tertiary recovery, or any other action with respect to the Subject Interests, the decision as to which would reasonably be expected to increase or reduce the quantity of Subject Hydrocarbons ultimately recoverable from the Subject Interests, or the rate of production therefrom; and (iv) such other information, technical or otherwise, as Lender may reasonably request (each such report an "Independent Reserve Report"); (o) promptly after June 30 of each calendar year (commencing with the calendar year 2002), and in any event not later than August 15 of such calendar year, a report in form and substance satisfactory to Lender and using pricing, engineering and other assumptions acceptable to Lender, prepared by Borrower effective as of June 30 of such calendar year updating the Independent Reserve Report and concerning (i) the quantity of Subject Hydrocarbons economically 41 recoverable based upon the assumptions provided by Lender from the Subject Interests, including the quantity of Proved Reserves, Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves, Proved Undeveloped Reserves, Probable Reserves and Possible Reserves; (ii) the Projected Income and Expense Attributable to the Subject Interests; (iii) any change in methods of treatment or operation of all or any wells on Subject Interests, any new drilling or development, any method of secondary or tertiary recovery, or any other action with respect to the Subject Interests, the decision as to which would reasonably be expected to increase or reduce the quantity of Subject Hydrocarbons ultimately recoverable from the Subject Interests, or the rate of production therefrom; and (iv) such other information, technical or otherwise, as Lender may reasonably request (each such report an "Internal Reserve Report"); (p) within a reasonable time of a reasonable request by Lender, an Independent Reserve Report where there have been substantial drilling operations, to be determined by Lender in its sole discretion, in respect of the Property of Borrower in the intermittent term between the delivery of the Independent Reserve Reports delivered pursuant to Section 7.3(n); provided that no such report will be requested more than three times per calendar year; (q) upon, but in no event later than ten (10) days after, any responsible officer of Borrower becomes aware thereof, notice of (i) any and all enforcement, cleanup, removal or other governmental or regulatory actions instituted, completed or threatened or other environmental claims against Borrower or any of the Subject Interests pursuant to any applicable Environmental Laws, or (ii) any environmental or similar condition on any Property adjoining or in the vicinity of the Property of Borrower that could reasonably be anticipated to cause such Property or any part thereof to be subject to any adverse restrictions on the ownership, occupancy, transferability or use of such Property under any Environmental Laws; (r) promptly after (i) the sending or filing thereof, copies of all reports which Borrower sends to any of its security holders, (ii) the sending or filing thereof, all material reports and registration statements which Borrower files with any securities commission or any national securities exchange, (iii) the filing thereof, copies of all tariff and rate cases and other material reports filed with any Governmental Authority (other than routine operating reports), and (iv) receipt thereof, copies of all notices received from any Governmental Authority concerning material noncompliance by Borrower with any Applicable Laws; and (s) with reasonable promptness, such other information respecting the condition or operations, financial or otherwise, of Borrower as Lender may from time to time reasonably request. All reports and other information herein described or otherwise described in this Agreement and all other reports which Borrower or Abraxas Petroleum Corporation is required to deliver pursuant to the terms and conditions hereof shall be prepared and delivered at the sole cost and expense of Borrower. 42 7.4 Gathering and Transportation and Other Services. Subject to the provisions of this Section 7.4 with respect to Lender acting as Borrower's agent and Article 11 with respect to Lender's preferential right to purchase Subject Hydrocarbons, Borrower at its sole cost and expense (provided Lender shall pay its pro rata cost for transport, delivery and marketing of the Override Hydrocarbons by a Person which is not an Affiliate of Borrower) shall cause all Subject Hydrocarbons to be produced, delivered, gathered, compressed, treated, processed, fractionated and marketed, as a reasonably prudent operator and without discrimination as to Override Hydrocarbons and Residual Hydrocarbons. If Lender reasonably determines that Borrower is not causing any Subject Hydrocarbons to be gathered, compressed, treated, processed and fractionated to prepare such Subject Hydrocarbons to be marketed meeting required pipeline specifications, as a reasonably prudent operator, or that Borrower is not causing any Subject Hydrocarbons to be marketed as a reasonably prudent operator, then Lender may, in its sole discretion, act as agent with respect to such Subject Hydrocarbons to obtain or provide such services as would a reasonably prudent operator and in the manner set forth in this Agreement. Borrower will fully cooperate with Lender in its capacity as agent with respect to any such services. 7.5 Collateral Coverage Deficiency or Collateral Coverage Default. Borrower shall at all times maintain a Collateral Coverage Ratio of 150% or greater, but in any event, Borrower shall notify Lender promptly after becoming aware that any event, condition or circumstance which has occurred or exists which could reasonably be expected to become or constitute a Collateral Coverage Deficiency or a Collateral Coverage Default. Within 30 days of such notice or any notice of a Collateral Coverage Deficiency received by Borrower from Lender, Borrower must either at Lender's sole discretion (i) make a prepayment in conformity with Section 3.1 in an amount sufficient to eliminate the Collateral Coverage Deficiency, or (ii) pledge to Lender additional Properties which are acceptable to Lender, in its sole discretion, in a manner and in an amount sufficient to eliminate the Collateral Coverage Deficiency. 7.6 Use of Proceeds. Borrower shall (i) use the proceeds of the Loans as set forth in Section 4.5 and (ii) not use the proceeds of the Loans to pay any dividends or other distributions (except as provided under Section 8.5), to purchase any of its shares, to make any loans or advance any monies to any employee (excluding normal business and travel expense advances), consultant or agent of Borrower or to pay any cost, expense or otherwise, except in connection with Borrower's oil and gas exploration, development and production business consistent with the Development Plan, except as provided in Section 4.5(a)(ii). 7.7 Joint Operating Agreement. Except as may be otherwise approved by Lender, in its sole and absolute discretion, Borrower shall comply with, and perform any and all obligations and actions set forth in, the terms and provisions of the Joint Operating Agreements. Borrower shall provide prompt notice of the execution of all joint operating agreements relating to the Subject Interests or the Subject Hydrocarbons and, upon request by Lender, deliver copies of such joint 43 operating agreements relating to the Subject Interests or the Subject Hydrocarbons to which Borrower is a party duly certified by an Authorized Officer of Borrower as being true, correct and complete, and such agreements shall be in form and substance satisfactory to Lender. 7.8 Compliance with Laws. Borrower shall conduct all of its business within, and comply in all material respects with, all Applicable Laws, such compliance to include the maintenance and preservation of its existence and qualification as a corporation in good standing in its jurisdiction of incorporation and each other jurisdiction where it carries on business and all Approvals necessary to permit each of them to carry on their respective businesses. 7.9 Production-Related Expenses and Taxes. Borrower shall pay, promptly when due, and in any event within 90 days of its payment due date, except as contested in good faith by appropriate proceedings, all amounts in any way owed or owing with respect of the Subject Interests, including all production-related expenses. Borrower shall make all required income tax filings prior to any applicable filing deadlines. Borrower shall pay, promptly when due, and in any event within 30 days of its payment due date, except as contested in good faith by appropriate proceedings and for which adequate reserve in accordance with GAAP shall have been set aside in its books, together with interest and penalties thereon, if any, all Taxes imposed on Borrower or any of its Properties, (whether by operation of law or pursuant to this Agreement), including those set forth below: (i) all ad valorem taxes (or Taxes imposed in lieu thereof) imposed upon or assessed with respect to or charged against the Subject Interests or the Subject Hydrocarbons; and (ii) all severance taxes and other Taxes, duties, imposts, charges, levies and assessments of any kind or nature whatsoever, imposed upon or assessed with respect to or charged against the Subject Interests or the Subject Hydrocarbons. 7.10 Operation of Subject Interests. Borrower shall, as an independent contractor and as a prudent operator and at Borrower's sole cost and expense: (i) cause the Subject Interests to be developed, maintained and continuously operated for the production of Hydrocarbons in a good and workmanlike manner, as would a prudent operator (without regard to the existence of the Debenture or the Override), all in accordance with the Development Plan, generally accepted practices, applicable operating agreements, and Applicable Laws (including all Environmental Laws), and in a manner intended to be consistent with the production rate assumptions used in, and the levels defined in, the various production profile data provided to Lender; (ii) pay, or cause to be paid, promptly, and no longer than 90 days from the billing date for such amount, as and when due and payable, (A) all rentals, royalties and operating, development, production and transportation expenses and proceeds payable to the other mineral interest owners in respect of the Subject Interests or the Subject Hydrocarbons, excepting those being contested in good faith, (B) all production related-expenses and production-related Taxes incurred in or arising from the operation or development of the Subject Interests, or the producing, treating, gathering, or storing, of the Subject Hydrocarbons; excepting those being contested in good faith or those not yet payable in the ordinary course of business, and (C) all general and administrative related expenses and Taxes, excepting those being contested in good faith or those not yet payable in the ordinary course of business; (iii) cause 44 machinery, equipment and facilities necessary for the production of the Subject Hydrocarbons to be kept in working order as would a prudent operator (without regard to the existence of the Debenture) and necessary repairs, renewals, renovations, replacements, additions and improvements thereof or thereto to be promptly made; (iv) give or cause to be given to Lender written notice of every adverse claim or demand made by any Person (other than Lender or the buyer of Hydrocarbons) affecting the Subject Interests or the Subject Hydrocarbons which could have a material adverse effect on the Override or any portion thereof or on Borrower, and of any suit or other legal proceeding instituted with respect thereto, and cause necessary steps to be taken with reasonable diligence to protect and defend the Subject Interests and the Subject Hydrocarbons against any such adverse claim or demand which could have a material adverse effect on the Override or any portion thereof, or Borrower, including the employment of counsel for the prosecution or defense of litigation; and (v) cause the Subject Interests to be kept free and clear of Liens or overriding royalty interests other than Permitted Liens. Borrower shall maintain, preserve, protect and keep the Subject Interests in good repair, working order and condition, and make necessary and proper repairs, renewals and replacements so that (A) its business carried on in connection therewith may be properly conducted at all times and (B) the Subject Interests do not decline in value. 7.11 Development Plan. Except as may otherwise be approved by Lender, in its reasonable discretion, Borrower shall comply with, and perform any and all obligations and actions set forth in, the terms and provisions of the Development Plan. Lender and Borrower acknowledge and agree that operations in the field will not follow exactly the Development Plan. Adjustments and modifications to the various "Approved Expenditures" will be necessitated by the drilling and operating conditions encountered by Borrower and its contract operators. Additionally, upsets and emergencies can occur which will necessitate immediate action by Borrower in order to save lives and Property. Accordingly, Lender agrees to work closely with Borrower in promptly responding to such changed circumstances and necessary modification to the Development Plan. As soon as available, and in any event within 30 days after the end of each calendar quarter, Borrower shall deliver to Lender for review a proposed updated Development Plan. Within ten (10) Business Days of its receipt of the updated Development Plan, Lender will notify Borrower if such proposed Development Plan is acceptable. Upon the written notification of Borrower by Lender that the updated Development Plan is acceptable, such updated Development Plan will be deemed to replace the then current Development Plan for all purposes under the Loan Documents. Upon written notification to Borrower that such proposed Development Plan is not acceptable, Borrower shall have a period of five (5) Business Days to submit a revised updated Development Plan to Lender for review under the terms of this Section 7.11. 7.12 Insurance. Borrower will maintain with financially sound and reputable insurance companies such insurance relating to the Subject Interests and the Subject Hydrocarbons in amount and type with such deductibles and against such risks, liabilities, casualties and contingencies as is maintained by prudent individuals in the industry (and which property insurance shall name Lender as an "additional insured" and as "sole 45 loss payee as to first party claims" as its interest may appear and shall contain endorsements to such policies providing that the insurer will notify Lender not less than 30 days prior to the expiration or termination of such policies), including (i) the insurance policy attached as Schedule III; and (ii) to the extent such insurance is carried by others engaged in the oil and gas exploration and production industry and in similar undertakings in the same general area or areas in which the Subject Interests are located, insurance on all personal property and fixtures used in connection with the operation of the Subject Interests, against loss or damage by fire, lightning, hail, tornado, explosion, hurricane and other similar risks, and (iii) OEE insurance during drilling operations. To the extent that Lender receives proceeds as a loss payee, such proceeds shall either be applied to the Obligations or to replace the damaged or lost Property, at Lender's sole discretion. Borrower shall furnish or cause to be furnished to Lender, upon the request of Lender (but no less than once each year), from time to time thereafter, a summary of the insurance coverage of Borrower in form and substance satisfactory to Lender in its sole discretion and copies of all applicable insurance policies. Unless otherwise specified, the deductible of each such insurance policy shall be in an amount not to exceed $25,000 per occurrence. 7.13 Accounting Principles. Unless otherwise specified, all accounting terms used herein or in any Loan Document shall be interpreted, and Borrower will, and will cause Abraxas Petroleum Corporation to, prepare all reports and financial statements and computations required under this Agreement or the other Loan Documents, all in accordance with GAAP consistently applied for all periods. Borrower will provide such information as Lender may request from time to time in accordance with accurate accounting standards customary and acceptable in the oil and gas exploration and production industry. 7.14 Books and Records; Inspections. (a) Borrower will keep books and records which accurately reflect all of their business affairs and transactions, or relate to the Subject Interests, and permit Lender or any of its representatives, at reasonable times and intervals, to visit all of its offices and the Subject Interests, to discuss its financial matters with its officers and independent public accountant (and Borrower hereby authorize such independent public accountant to discuss the financial matters of Borrower with Lender or its representatives whether or not any representative of Borrower is present) and to examine (and, at the expense of Borrower, photocopy extracts from) any of its books or other corporate records. Borrower shall pay any fees and expenses incurred in connection with Lender's exercise of its rights pursuant to this Section 7.14. (b) Furthermore, Borrower will permit Lender, or its agents, at the cost and expense of Borrower but at Lender's risk, to enter upon the Subject Interests and all parts thereof, for the purpose of investigating and inspecting the condition and operation thereof, and shall permit reasonable access to the field offices and other offices, including the principal place of business, of Borrower to inspect and examine the Subject Interests. 46 7.15 Environmental Covenant. Borrower will (i) use and operate all of its facilities and Properties in material compliance with all Environmental Laws, keep all necessary Approvals relating to environmental matters in effect and remain in material compliance therewith, and handle all Hazardous Materials in material compliance with all applicable Environmental Laws, (ii) promptly cure and have dismissed with prejudice to the satisfaction of Lender any actions and proceedings relating to compliance with Environmental Laws, and diligently pursue the cure of any material underlying environmental problem which forms the basis of any such claim, complaint, notice or inquiry, and (iii) provide such information and certifications which Lender may reasonably request from time to time to evidence compliance with this Section 7.15. Borrower will provide an Environmental Certificate to Lender at the same time as the delivery of the annual financial statements of Borrower referred to in Section 7.3(b). 7.16 Board of Directors Meetings. As soon as available and in any event 30 days prior to any such meeting, Borrower shall deliver to Lender notice of any meeting of the Board of Directors of Borrower, any committee of Borrower or any meetings of the shareholders of Borrower. Borrower hereby grants to Lender the right to attend any such meetings as a non-voting observer. 7.17 Hedging Agreements. Promptly, and in any event within 10 days of receipt by Borrower of a written request from Lender, Borrower shall have entered into one or more swap, hedge, floor, collar or other similar agreements which are satisfactory to Lender at a price and for a term which is mutually acceptable to Borrower and Lender pursuant to the ISDA Master Agreement (each a "Initial Hedging Agreement") and satisfactory to Lender. 7.18 Protection of Security. Borrower shall do all things reasonably requested by Lender to protect, preserve and maintain the Subject Interests, the value thereof and the priority of the Liens granted in favour of Lender pursuant to the Loan Documents in relation to other Persons. 7.19 Grant Fixed Charge Security. If Lender considers it necessary for its adequate protection, Borrower, at the request of Lender, shall forthwith grant or cause to be granted to Lender, a fixed Lien (subject only to Permitted Liens which under Applicable Law rank in priority thereto) in such of Borrower's Property as Lender shall, in its sole discretion, determine as security for all then present and future Indebtedness of Borrower to Lender and its Affiliates under the Loan Documents. In this connection, Borrower shall: (a) provide Lender with such information as is reasonably required by the Agent to identify the property to be charged pursuant to this Section 7.19; (b) do all such things as are reasonably required to grant in favour of Lender a fixed Lien (subject only to Permitted Liens which under Applicable Law rank in priority thereto) in respect of such property to be so charged pursuant to this Section 7.19; 47 (c) provide or cause to be provided to Lender with all corporate resolutions and other action, as reasonably required, for Borrower to grant to Lender a fixed Lien (subject only to Permitted Liens which under Applicable Law rank in priority thereto) in the property identified by Lender to be so charged; (d) provide Lender with such security instrument, legal opinions and other documents which Lender, acting reasonably, deems are necessary to give full force and effect to the provisions of this Section 7.19; (e) assist Lender in the registration or recording of such agreements and instruments in such public registry offices in Canada or any province thereof as Lender, acting reasonably, deems necessary to give full force and effect to the provisions of this Section 7.19; and (f) pay all reasonable costs and expenses incurred by Lender in connection with the preparation, execution and registration of all agreements, documents and instruments, including any amendments to any Loan Document, made in connection with this Section 7.19. 7.20 Further Assurances. (a) Borrower shall, upon the request of Lender, take such actions and execute and deliver such documents and instruments as Lender reasonably shall require to ensure that Lender shall, at all times, have received currently effective duly executed Loan Documents encumbering the Subject Interests of Borrower constituting 100% of the Proven Reserves of Borrower to which value is given in the determination of the then current Risked NPV10 (with accompanying letters in lieu of transfer orders) and satisfactory title evidence in form and substance reasonably acceptable to Lender as to ownership of such the Subject Interests. (b) If Lender shall determine that, as of the date of any determination of the Collateral Coverage Ratio, Borrower shall have failed to comply with the Section 7.20(a), Lender may notify Borrower in writing of such failure and, within 30 days from and after receipt of such written notice by Borrower, Borrower shall execute and deliver to Lender supplemental or additional Loan Documents, in form and substance reasonably satisfactory to Lender and its counsel, securing payment of the Obligations and covering additional assets not then encumbered by any Loan Documents (together with current valuations, Independent Engineering Reports, and title evidence applicable to the additional assets collaterally assigned, each of which shall be in form and substance reasonably satisfactory to Lender) such that Lender shall have received currently effective duly executed Loan Documents encumbering Subject Interests constituting 100% of the Proven Reserves of Borrower to which value is given in the determination of the then current Risked NPV10 (with accompanying letters in lieu of transfer orders) and satisfactory title evidence in form and substance acceptable to Lender as to ownership of such Subject Interests. 48 (c) Borrower will execute any and all further documents, financing statements, agreements and instruments, and take all such further actions (including the filing and recording of financing statements, fixture filings, mortgages, debentures, security agreements, pledge agreements, deeds of trust and other documents), which may be required under any Applicable Law, or which Lender may reasonably request, to effectuate the transactions contemplated by the Loan Documents or to grant, preserve, protect or perfect the Liens created or intended to be created by the Loan Documents or the validity or priority of any such Lien, all at the expense of Borrower. Borrower agrees to provide to Lender, from time to time upon reasonable request of Lender, information which is in the possession of Borrower or otherwise reasonably obtainable by any of them, reasonably satisfactory to Lender as to the perfection and priority of the Liens created or intended to be created by the Loan Documents. (d) Borrower hereby authorizes Lender to file one or more financing or continuation statements, and amendments thereto, relative to all or any part of the Subject Interests or other collateral granted by Borrower to Lender without the signature of Borrower where permitted by Applicable Law. A carbon, photographic or other reproduction of the Loan Documents or any financing statement covering the Subject Interests or other collateral granted by Borrower and any other Obligor to Lender or any part thereof shall be sufficient as a financing statement where permitted by Applicable Law. (e) Upon the acquisition of any new Properties by Borrower, Borrower shall execute to and in favour of Lender, within 30 days of any such acquisition, a "Royalty Lands Addition Schedule" which is attached to the Override Royalty Agreements, describing the acquired Properties. 7.21 Override Records. Borrower shall at all times cause the Overrides described in the Override Royalty Agreements to be recorded in reasonable detail on the books and records of Borrower in respect of its Subject Interests and such books and records are to be maintained in accordance with prudent industry practice. Borrower will make such books and records available for review by Lender or its representatives during regular business hours at the offices of Borrower upon reasonable notice by Lender. 7.22 Title Deficiencies. Borrower agrees that it will use all commercially reasonable efforts to correct, explain or otherwise resolve to the satisfaction of the Lender, the title deficiencies that appear on the memorandum attached hereto as Schedule VIII on or prior to February 1, 2002. 7.23 Further Due Diligence. Borrower agrees that prior to commencing operations on each well to be drilled pursuant to the Development Plan, it will provide Lender with reasonable title verification in respect of the Property on which such well is located, in form and scope satisfactory to Lender and such title verification shall be performed by a law firm acceptable to Lender, acting reasonably. 49 Article 8 NEGATIVE COVENANTS 8.1 Negative Covenants. Borrower agrees with Lender that, until the unconditional and irrevocable payment in full in cash of all accrued and outstanding monetary Loan Obligations and the termination or expiration of the Commitment, Borrower will or will cause each of its Subsidiaries to, perform, or not perform, as applicable, the obligations set forth in this Article 8. 8.2 Business Activities. Borrower will not engage, or permit any of its Subsidiaries to engage, in any business activity, except the acquiring, owning, operating, producing, gathering, treating, processing, transportation and marketing of Hydrocarbons and such activities as may be incidental or related thereto, without the prior written consent of Lender, in its sole and absolute discretion. 8.3 Indebtedness. Borrower will not, and will not permit any of its Subsidiaries to, create, incur, assume or suffer to exist or otherwise become or be liable in respect of any Indebtedness, other than, without duplication, (i) Indebtedness in respect of the Loans and other Obligations, (ii) unsecured Indebtedness incurred in the ordinary course of business (including (A) open accounts extended by suppliers on normal trade terms in connection with purchases of goods and services and (B) gas balancing, but excluding Indebtedness incurred through the borrowing of money or Contingent Liabilities) and (iii) Indebtedness not to exceed $100,000 for immediately required plugging and abandoning obligations, surety bonds, performance bonds and similar obligations and bonds; provided, however, that no Indebtedness otherwise permitted by clause (ii) above shall be permitted if, after giving effect to the incurrence thereof, any Default or Event of Default shall have occurred and be continuing. 8.4 Liens. Borrower will not, and will not permit any of its Subsidiaries to, create, incur, assume or suffer to exist any Lien upon any of its Property or revenues, whether now owned or hereafter acquired, except for Permitted Liens. 8.5 Restricted Payments, etc. On and at all times after the Effective Date, Borrower will not, and will not permit any of its Subsidiaries to, except as permitted pursuant to Section 4.5(a)(ii), declare, pay or make any dividend or distribution (in cash, property or obligations) on any interest or shares or capital stock (now or hereafter outstanding) of Borrower or on any interest or shares of any class or capital stock (now or hereafter outstanding) of Borrower or such Subsidiary or apply any of its funds, property or assets to the purchase, redemption, sinking fund or other retirement of any class of shares of any class or capital stock (now or hereafter outstanding) of Borrower or such Subsidiary, or warrants, options or other rights with respect to any interest or shares of any class or capital stock (now or hereafter outstanding) of Borrower or such Subsidiary, without the prior written consent of Lender, which consent may be withheld by Lender in its sole and absolute discretion. Borrower will not permit any Subsidiary to make any distributions other than to Borrower. Borrower will not, and will not permit its Subsidiaries to, make any deposit for any purpose that violates the provisions of this Section 8.5. 50 8.6 Capital Expenditures. (a) Borrower will not, and will not permit any of its Subsidiaries to, make or commit to make Capital Expenditures in any calendar year, except Capital Expenditures set forth in the current "Capital Expenditures" section of the Development Plan. (b) Except as may otherwise be approved by Lender, in its sole and absolute discretion, Borrower shall not, and will not permit any of its Subsidiaries to, make (i) any expenditures which are not set forth in the Development Plan or (ii) any payment for any expenditure in excess of the amount set forth in the Development Plan for such expenditure; provided, however, that, notwithstanding the foregoing, Borrower may make aggregate annual expenditures of up to $400,000 which are not in conformity with the Development Plan, and such payments shall be deemed approved amounts for the purposes of Section 3.4(b). 8.7 Accounts Receivable. Borrower shall not, and will not permit any of its Subsidiaries to, sell or discount any of its accounts receivable without the prior written consent of Lender. 8.8 Rental Obligations. Without the prior written consent of Lender, Borrower will not, and will not permit any of its Subsidiaries to, enter into at any time any arrangement which creates a Capitalized Lease Liability and which involves the leasing by Borrower from any lessor of any Property (or any interest therein), except arrangements which exist as of the Effective Date (or any renewals or replacements thereof) or are approved under the Development Plan or together with all other such arrangements which will then be in effect, will not require the payment of an aggregate amount of rentals by Borrower and its Subsidiaries (in aggregate) in excess of (excluding escalations resulting from a rise in the consumer price or similar index) $75,000 for any calendar year or $150,000 during the full remaining term of such arrangements. 8.9 Take-or-Pay Contracts. Without the prior written consent of Lender, in its sole and absolute discretion, Borrower will not, and will not permit any of its Subsidiaries to, enter into or be a party to any arrangement for the purchase of materials, supplies, other Property (including Hydrocarbons) or services if such arrangement requires that payment be made by Borrower or such Subsidiaries regardless of whether such materials, supplies, other property or services are delivered or furnished to it. 8.10 Consolidation, Merger, etc. Except for the Abraxas Amalgamation, Borrower will not, and will not permit any of its Subsidiaries to, liquidate or dissolve, consolidate with, or merge into or with, any other Person, or purchase or otherwise acquire all or substantially all of the assets of any Person (or of any division thereof), without the prior written consent of Lender. 8.11 Asset Dispositions, etc. Except as permitted by Section 4.3, without the prior written consent of Lender, in its sole and absolute discretion after reasonable consultation with Borrower, Borrower will not, and will not permit any of its Subsidiaries to, sell, transfer, lease, contribute or otherwise convey, or grant options, warrants or other rights with respect to, all or any substantial part of its Property or the Subject Interests to any Person. Borrower will at all 51 times be the legal and beneficial owner of the Subject Interests. Borrower will not, and will not permit any of its Subsidiaries to, change its name, identity, principal place of business or the office where it keeps its books and records concerning the Override, the Production Sale Contracts and the contract rights and accounts now existing or hereafter arising in connection therewith without notifying Lender in writing of any such change at least 30 days prior to the effective date of such change. 8.12 Abandonment of Wellbores or Conduct of Certain Operations. Without first obtaining the written consent of Lender, Borrower will not, and will not permit any of its Subsidiaries to, (i) abandon any wellbore on the Subject Interests which is capable of producing in paying quantities heretofore or hereafter completed for production of Hydrocarbons; or (ii) conduct any work or operation in any wellbore of a Subject Interest, which work or operation is related to any zone, horizon, formation or interval not included in the Subject Interests. For all purposes of this Agreement and the Override Royalty Agreement, a well shall be deemed to be capable of producing Hydrocarbons "in paying quantities" unless and until there arises a condition, which reasonably appears to be permanent, such that the aggregate value of the Subject Hydrocarbons which are being produced or will be produced from such well (without considering the effect of the Override) no longer exceeds or will not exceed the costs and expenses directly related to the operation and maintenance of such well. 8.13 Grant Liens, Mortgage or Transfer or Resignation as Operator of any Subject Interest. Except as permitted by Section 4.4, without first obtaining the written consent of Lender which shall not unreasonably be withheld, Borrower will not, and will not permit any of its Subsidiaries to, (i) sell, assign, lease, mortgage, hypothecate, pledge, or otherwise transfer the interest of Borrower and its Subsidiaries in any of the Subject Interests, either in whole or in part, except for Permitted Liens and, to the extent permitted by Applicable Law, any purported sale, assignment, lease, mortgage or hypothecation or other transfer in contravention hereof shall be null and void; or (ii) resign as operator of any of the Subject Interests operated by Borrower or such Subsidiary unless the successor operator has been approved in writing by Lender or, following the occurrence of a Default or an Event of Default, Lender shall have requested in writing such resignation. 8.14 Modification of Certain Agreements. Borrower will not, and will not permit any of its Subsidiaries to, permit, or otherwise consent to, any amendment, supplement or other modification of any of the terms or provisions contained in, or applicable to, any Transportation Agreements, any Joint Operating Agreement or any gathering or marketing agreement with Lender, without the prior written consent of Lender which shall not unreasonably be withheld. 8.15 Pension Plans. Without the prior written consent of Lender which shall not unreasonably be withheld, Borrower will not create or permit to exist any pension or similar plan, other than those attached hereto as Schedule V, and any renewal of equivalent replacement thereof. 52 8.16 Other Agreements. Borrower will not, and will not permit any of its Subsidiaries to, enter into any agreement containing any provision which would be violated or breached by the performance of their obligations under the Loan Documents or under any instrument or document delivered or to be delivered by Borrower or any of its Subsidiaries thereunder or in connection therewith. 8.17 No Subsidiaries. Without the prior written consent of Lender, in its sole and absolute discretion, Borrower will not, and will not permit any of its Subsidiaries to, at any time create or acquire any new Subsidiary or enter into any partnership, joint venture or other business, other than in the ordinary course of business. 8.18 No Other Hedging Agreements. Except for the ISDA Master Agreement and any Borrower Hedging Agreement, entered into in connection with such ISDA Master Agreement, Borrower will not, and will not permit any of its Subsidiaries to, enter into any other ISDA master agreement or any Hedging Agreement except pursuant to the ISDA Master Agreement. 8.19 Transactions with Affiliates. Borrower will not, and will not permit any of its Subsidiaries to, enter into, or cause, suffer or permit to exist any arrangement or contract with any of its Affiliates, unless Borrower or such Subsidiary has obtained the prior written consent of Lender in its sole discretion to such transaction. 8.20 Negative Pledges, Restrictive Agreements, etc. Borrower will not, and will not permit any of its Subsidiaries to, enter into any agreement prohibiting: (a) the creation or assumption of any Lien in favor of Lender upon its Properties, revenues or assets, whether now owned or hereafter acquired, or the ability of Borrower to amend or otherwise modify this Agreement or any other Loan Document; or (b) the ability of any Subsidiary to make any payments, directly or indirectly, to Borrower by way of dividends, advances, repayments of loans or advances, reimbursements of management and other intercompany charges, expenses and accruals or other returns on investments, or any other agreement or arrangement which restricts the ability of any such Subsidiary to make any payment, directly or indirectly, to Borrower. 8.21 Limitations on Certain Financing Leases and Sale and Leaseback Transactions. Borrower will not, and will not permit any Subsidiary to, enter into any synthetic lease or leveraged lease arrangement with any Person or enter into any arrangement with any Person providing for the leasing by Borrower or any Subsidiary of any Property, which Property is or has been sold or transferred by Borrower or any Subsidiary to such Person in contemplation of taking back a lease thereof, other than those described in Schedule VII. 8.22 Dissemination of Information. Borrower will not, and will not permit any Subsidiary to, cause or otherwise permit (i) any information in any way relating to the transaction contemplated by the Loan Documents to 53 be disseminated, quoted from or referred to at any time, in any manner or for any purpose, or (ii) any public reference to Lender to be made by Borrower in any press release or similarly public transmission, without the prior written consent in each specific instance of Lender, in its sole and absolute discretion, except to the extent required to be disclosed by Applicable Law or by any order, rule, regulation or legal process (whether valid or invalid) of any court or Governmental Agency. 8.23 Subject Interests. Borrower will not, and will not permit any of its Subsidiaries to, enter into any new agreements or assign or modify the terms of any existing agreements, relating to or affecting the Subject Properties' mineral interests, including additional override burdens or interests. Article 9 EVENTS OF DEFAULT 9.1 Events of Default. Each of the following events or occurrences described in this Section 9.1 shall constitute an "Event of Default". (a) Non-Payment of Obligations. Borrower shall default in the payment or prepayment when due of any principal of, or interest on, any Loan; or Borrower shall default (and such default shall continue unremedied for a period of five (5) days) in the payment when due of any other Obligation. (b) Breach of Warranty. Any representation or warranty of Borrower or any other Obligor made or deemed to be made hereunder or in any other Loan Document executed by it or any other writing or certificate furnished by or on behalf of Borrower or any other Obligor to Lender for the purposes of or in connection with this Agreement or any other Loan Document (including any certificates delivered pursuant to Article 5) is or shall be incorrect when made in any material respect. (c) Non-Performance of Certain Covenants and Obligations. A default in the due performance by Borrower or any other Obligor of any covenant or express agreement contained in this Agreement or any other Loan Document, and continuation of such default beyond the applicable grace period expressly granted in this Agreement or any such other Loan Document, if any, with respect thereto. (d) Collateral Coverage Default. Subject to Section 9.2(a)(iv), any occurrence of a Collateral Coverage Default. (e) Default on Other Indebtedness. (i) A default shall occur in the payment when due (subject to any applicable grace period), whether by acceleration or otherwise, of any Indebtedness (including any Hedging Obligations under a Hedging Agreement in effect between Borrower and Lender or an Affiliate of Lender) of Borrower or a default shall occur in the performance or 54 observance of any obligation or condition with respect to such Indebtedness if the effect of such default is to accelerate the maturity of any such Indebtedness or such default shall continue unremedied for any applicable period of time sufficient to permit the holder or holders of such Indebtedness, or any trustee or agent for such holders, to cause such Indebtedness to become due and payable prior to its expressed maturity. (ii) A failure to pay when due (or within 30 days after written demand) any royalty, overriding royalty or similar interest burdening the Subject Interests unless (A) such royalty, overriding royalty or similar interest is being disputed in good faith by Borrower, and (B) Borrower establishes a suspense account acceptable to Lender and any disbursement from such suspense account other than to a non-affiliated interest owner who Borrower has determined is the rightful owner of the suspended funds subject to the prior written approval of Lender. (f) Judgments. Any judgment or order for the payment of money in excess of $50,000 shall be rendered against Borrower and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order, or (ii) there shall be any period of ten (10) consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect. (g) Control of Borrower. Any Change of Control shall occur. (h) Bankruptcy, Insolvency. If a judgment, decree or order of a court of competent jurisdiction is entered against Borrower or any Obligor, (i) adjudging Borrower or any such Obligor bankrupt or insolvent, or approving a petition seeking its reorganization or winding-up under the Bankruptcy and Insolvency Act (Canada), the Companies' Creditors Arrangement Act (Canada) or any other bankruptcy, insolvency or analogous Applicable Law, or (ii) appointing a receiver, trustee, liquidator, or other Person with like powers, over all, or substantially all, of the Property of Borrower or any such Obligor or any of the Subject Interests; (iii) ordering the involuntary winding up or liquidation of the affairs of Borrower or any such Obligor or (iv) if any receiver or other Person with like powers is appointed over all, or substantially all, of the Property of Borrower or any such Obligor, or any of the Subject Interests; unless, in any such case, such judgment, petition, order or appointment is stayed and of no effect against the rights of Lender under the Loan Documents within 30 days of its entry and Lender is satisfied that there is no adverse effect in its position as a result of Lender permitting Borrower time to pursue such stay. (i) Winding-Up. If, (i) an order or a resolution is passed for the dissolution, winding-up, reorganization or liquidation of Borrower or any other Obligor pursuant to Applicable Law, including the Business Corporations Act (Alberta), or (ii) Borrower or any such Obligor institutes proceedings to be adjudicated bankrupt or insolvent, or consents to the institution of bankruptcy or insolvency proceedings against it 55 under the Bankruptcy and Insolvency Act (Canada), the Companies' Creditors Arrangement Act (Canada) or any other bankruptcy, insolvency or analogous Applicable Law, or (iii) Borrower or any such Obligor consents or acquiesces to the filing of any petition under any such Applicable Law or to the appointment of a receiver, or other Person with like powers, over all, or substantially all, of Borrower's or any such Obligor's Property or the Subject Interests, or (iv) Borrower or any such Obligor makes a general assignment for the benefit of creditors, or becomes unable to pay its debts generally as they become due, or (v) Borrower or any such Obligor takes or consents to any action in furtherance of any of the aforesaid purposes. (j) Impairment of Security, etc. Any Loan Document, or any Lien granted thereunder, shall (except in accordance with its terms), in whole or in part, terminate, cease to be effective or cease to be the legally valid, binding and enforceable obligation of Borrower; Borrower or any other Person shall, directly or indirectly, contest in any manner such effectiveness, validity, binding nature or enforceability; or any Lien securing any Obligation shall, in whole or in part, cease to be a perfected first Lien. (k) Cumulative Reimbursable Expenses Amount. The aggregate total of all Reimbursable Expenses paid by Lender and which Lender has not received a reimbursement from Borrower pursuant to Section 9.2(a)(iii) shall exceed $50,000. (l) Material Adverse Change. A material adverse change, as determined by Lender in its sole and absolute discretion, in the business, financial condition or results of operations in Borrower's ability to perform or their respective obligations under any Loan Documents to which it is a party. (m) Dissemination of Information. The breach by Borrower of the requirements of Section 8.22. 9.2 Remedies of Lender. (a) If an Event of Default: (i) described in Sections 9.1(a), (b), (c), (e), (f), or (k) (other than in respect of a payment) shall have occurred, Lender may provide Borrower with written notice specifying in reasonable detail the Event of Default which has occurred and stating that it intends to exercise remedies provided in this Section 9.2. Borrower shall then have 30 days after receipt of such notice to cure or cause to be cured such default and to provide Lender with notice and reasonable documentation that it has cured or cause to be cured such Event of Default. If Borrower does not provide such proper notice and evidence, then Lender may immediately by notice to Borrower reduce the Commitment Amount to zero and/or declare all or any portion of the outstanding principal amount under this Agreement and other Obligations to be due and payable whereupon the full 56 unpaid amount under this Agreement and other Obligations which shall be so declared due and payable shall be and become immediately due and payable, without further notice, demand or presentment, and Lender may exercise, in addition to other remedies available at law or in equity or pursuant to the other Loan Documents, the remedies set forth in Section 9.2(b); (ii) in Sections 9.1(h) and 9.1(i) shall have occurred, then the outstanding principal amount under this Agreement and all other Obligations shall automatically be and become immediately due and payable, without notice or demand and Lender may exercise, in addition to other remedies available at law or in equity or pursuant to the other Loan Documents, the remedies set forth in Section 9.2(b); provided, however, that Lender may not exercise such remedies if Borrower or any other Obligor, as the case may be, shall have cured each such Event of Default to the reasonable satisfaction of Lender prior to the time when Lender elects to exercise such remedies; (iii) described in Section 9.1(k) shall have occurred, and if Lender shall have paid or incurred a Reimbursable Expense in connection therewith, Lender shall notify Borrower in writing of such payment(s), and if Borrower does not fully reimburse Lender within ten (10) days of receipt of such notice, Lender shall be entitled by notice to Borrower to declare all or any portion of the outstanding principal amount under this Agreement and other Obligations to be due and payable whereupon the full unpaid amount under this Agreement and other Obligations which shall be so declared due and payable shall be and become immediately due and payable, without further notice, demand or presentment, and Borrower may exercise, in addition to other remedies available at law or in equity or pursuant to the other Loan Documents, its remedies under Section 9.2(b). (iv) If an Event of Default described in Section 9.1(d) shall have occurred, Lender may provide Borrower with written notice specifying in reasonable detail the Event of Default which has occurred and stating that it intends to exercise remedies provided in this Section 9.2. Borrower shall then have 60 days after receipt of such notice to (A) cure or cause to be cured such default by either (x) making a prepayment in conformity with Section 3.1 in an amount sufficient to eliminate the Collateral Coverage Default, or (y) pledge to Lender additional properties which are acceptable to Lender, in its sole discretion, in an manner and in an amount sufficient to eliminate the Collateral Coverage Default, and (B) provide Lender with notice and reasonable documentation that it has cured or cause to be cured such Event of Default. If Borrower does not provide such proper notice and evidence, then Lender may immediately by notice to Borrower declare all or any portion of the outstanding principal amount under this Agreement and other Obligations to be due and payable whereupon the full unpaid amount under this Agreement and other Obligations which shall be so declared due and payable 57 shall be and become immediately due and payable, without further notice, demand or presentment, and Lender may exercise, in addition to other remedies available at law or in equity or pursuant to the other Loan Documents, the remedies set forth in Section 9.2(b). (v) If an Event of Default shall have occurred, then Lender may by notice to Borrower declare all or any portion of the outstanding principal amount under this Agreement and other Obligations to be due and payable whereupon the full unpaid amount of the Loans and other Obligations which shall be so declared due and payable shall be and become immediately due and payable, without further notice, demand or presentment, and Borrower may exercise, in addition to other remedies available at law or in equity or pursuant to the other Loan Documents, its remedies Section 9.2(b). (b) After the occurrence of an Event of Default, and in addition to Lender's right to recover damages, all remedies set forth in Section 9.2(a) and all other remedies available to Lender provided by Applicable Law or in equity or pursuant to the Loan Documents, including the Debenture and the Debenture Pledge Agreement, Lender may (but is not obligated or required to) exercise any or all of the following remedies: (i) perform or cause to be performed or pay at Borrower's expense the act or matter the failure of which resulted in the Event of Default, in which event Lender may expend funds for such purpose; (ii) take any and all actions necessary to protect the Property secured by the Debenture and the other security documents referred to in Section 5.4, including taking any legal actions or paying any amounts or settling any claims; (iii) apply any amounts deposited in the Collateral Account as a prepayment on the Loans outstanding under this Agreement pursuant to Section 3.1; (iv) after written notice to Borrower, exercise all rights of Borrower with respect to the possession, operation and development of some or all of the Subject Interests, including the right to operate some or all of the Subject Interests; (v) exercise the right to notify the purchasers of the Subject Hydrocarbons to make direct payment to Lender; (vi) have the use, in connection with operating the Subject Interests, of any or all of the Property of Borrower located thereon or used in connection therewith as then may be useful or appropriate for the production, treating, storing, and transporting of Subject Hydrocarbons and Borrower hereby grant 58 Lender a non-exclusive easement and license to use any and all such Property in the event of such occurrence; (vii) Lender may on behalf of and for the account of Borrower, sell or utilize all of the Subject Hydrocarbons and apply the proceeds thereof attributable to interest of Borrower therein to the costs and expenses of the operation and development of the Subject Interests and to reimburse Lender for any amounts so expended by Lender; (viii) in the event of the occurrence of an Event of Default, Lender may request and require Borrower to resign as record title operator of the Subject Interests and take all actions necessary to replace Borrower as record title operator, including replacing Borrower as record title operator with Lender or any of its Affiliates or any third-party, and Borrower agrees (A) to cooperate fully in each and every way in connection with the replacement of the operator of the Subject Interests, including agreeing to withdraw as record title operator of the Subject Interests, (B) to vote for and otherwise support Lender's designated interim record title operator until a successor record title operator is elected pursuant to the terms and provisions of any joint operating agreement, and (C) to vote for and otherwise support Lender's choice as record title operator pursuant to the terms and provisions of any joint operating agreement; provided that Borrower -------- ---- shall remain obligated for all obligations, costs and expenses arising from serving as record title operator of the Subject Interests. (c) Upon demand, after the occurrence of an Event of Default, Borrower shall reimburse Lender for all reasonable amounts expended (including the fees and out-of-pocket expenses of counsel (on a solicitor and his own client basis) in connection therewith, the costs incurred by Lender in connection with the rescheduling of committed Hydrocarbon deliveries, the termination of any existing contracts or agreements and any pipeline service costs) by Lender (such expended amounts to be included as Reimbursable Expenses) as a result of or in connection with its exercise of remedies, together with interest on such amounts at the Default Rate from the date incurred until reimbursed. (d) Upon demand, after the occurrence of an Event of Default, Borrower shall submit an updated Development Plan. (e) The rights provided for in this Agreement and the other Loan Documents are cumulative and are not exclusive of any other rights, powers, privileges or remedies provided by Applicable Law or in equity, or under any other instrument, document or agreement, including the Loan Documents, now existing or hereafter arising. 59 Article 10 OVERRIDE ROYALTY AGREEMENT 10.1 Override Royalty Agreement. (a) Upon Lender receiving a 17.5% Cumulative Return on Total Funding under this Agreement, Lender shall reconvey, or shall cause to be reconveyed, the Override described in the Override Royalty Agreement No. 2 to Borrower and Lender shall take all steps reasonably necessary to effect such registrations, if any, as are necessary to effect such conveyances. (b) Upon Lender receiving the Payout Amount pursuant to Section 3.2, Lender shall reconvey, or shall cause to be reconveyed, the Override described in the Override Royalty Agreement No. 1 to Borrower and Lender shall take all steps reasonably necessary to effect such registrations, if any, as are necessary to effect such conveyances. Article 11 HYDROCARBON PURCHASE TERMS AND PROVISIONS 11.1 General. Lender, or any Affiliate of Lender, shall have the preferential right, but not the obligation, to purchase any Subject Hydrocarbons after any gathering, treating and processing utilized to prepare the Subject Hydrocarbons to be marketed meeting standard pipeline specifications, in accordance with the terms and conditions of this Article 11 from the Effective Date until the date on which the unconditional and irrevocable payment in full in cash of all accrued and outstanding monetary Loan Obligations is received by Lender and the termination or expiration of the Commitment. Such preferential right may be exercised from time to time during the period described in the preceding sentence upon thirty (30) days' written notice to Borrower. Lender shall purchase such Subject Hydrocarbons for a purchase price equal to their fair market value to be determined pursuant to a method acceptable to both Borrower and Lender. Lender or such Affiliate, as applicable, may, in its sole discretion, cease purchasing Subject Hydrocarbons from any or all wells or delivery points upon thirty (30) days' written notice to Borrower. In either case, Lender's election shall be effective on the first day of the first calendar month that begins after the expiration of the applicable thirty (30) day notice period. Without the prior written consent of Lender (which consent may be withheld in its sole and absolute discretion), Borrower will not, and will cause each of its Subsidiaries not to, enter into, or cause, suffer or permit to exist any arrangement or contract for the marketing of Subject Hydrocarbons with any Person other than Lender or an Affiliate of Lender; provided, however, that in the event Lender or such Affiliate elects not to purchase Subject Hydrocarbons in accordance with this Section 11.1, Borrower or any of its Subsidiaries may sell or contract to sell such Subject Hydrocarbons to any Person for a period not exceeding one (1) calendar month without the prior written consent of Lender (which consent may be withheld in Lender's sole discretion). In such case, Lender shall not be entitled to exercise the preferential rights until the expiry of such approved term. Any Subject Hydrocarbons consisting of natural gas, casinghead gas and other gaseous Hydrocarbons sold by Borrower and purchased by 60 Lender, or an Affiliate of Lender, as the case may be, shall be sold and purchased under the terms and conditions mutually acceptable to Lender and Borrower (and in any event, no less than the fair market value). Any Subject Hydrocarbons consisting of crude oil, condensate and other liquid Hydrocarbons sold by Borrower and purchased by Lender shall be sold and purchased under terms and conditions mutually acceptable to Lender and Borrower. At any time that Lender purchases any Subject Hydrocarbons, such purchase shall not be construed as Lender marketing Subject Hydrocarbons or causing such Subject Hydrocarbons to be marketed, and Borrower shall have no further interest or responsibility whatsoever with respect to such Subject Hydrocarbons purchased by Lender. 11.2 Marketing Subject Hydrocarbons to Third Persons. It is contemplated that Borrower may market, directly or indirectly, Subject Hydrocarbons to third Persons, as provided in Section 11.1. In such instances, Lender and Borrower shall execute letters in lieu (the "Letters in Lieu") before marketing Subject Hydrocarbons to such Persons. The Letters in Lieu shall be (i) addressed to the Person(s) purchasing the Subject Hydrocarbons, (ii) executed and delivered by both Borrower and Lender (or its Affiliate), (iii) shall require payment of the proceeds from the sale of the Hydrocarbons to the Collateral Account and otherwise in accordance with Section 3.4(a), and shall otherwise be in form and substance satisfactory to Lender, in its sole discretion and (iv) can be revoked or terminated only by a written instrument addressed to the Person(s) purchasing the Subject Hydrocarbons, and signed by both Borrower and Lender. Article 12 MISCELLANEOUS PROVISIONS 12.1 Waivers, Amendments, etc. The provisions of this Agreement and of each other Loan Document may from time to time be amended, modified or waived, if such amendment, modification or waiver is in writing and consented to by Borrower and Lender and in the case of Loan Documents to which a Subsidiary of Borrower is a party, such Subsidiary. No failure or delay on the part of Lender in exercising any power or right under this Agreement or any other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such power or right preclude any other or further exercise thereof or the exercise of any other power or right. No notice to or demand on Borrower in any case shall entitle it to any notice or demand in similar or other circumstances. No waiver or approval by Lender under this Agreement or any other Loan Document shall, except as may be otherwise stated in such waiver or approval, be applicable to subsequent transactions. No waiver or approval hereunder shall require any similar or dissimilar waiver or approval thereafter to be granted hereunder. 12.2 Notices. All notices and other communications provided to any party hereto under this Agreement or any other Loan Document shall be in writing or by facsimile and addressed, delivered or transmitted to such party at its address or facsimile number set forth below its signature hereto or at such other address or facsimile number as may be designated by such party in a notice to the other parties. Any notice, if mailed and properly addressed with postage prepaid or if properly addressed and sent by pre-paid courier service, shall be deemed given 61 when received; any notice, if transmitted by facsimile, shall be deemed given when transmitted. 12.3 Payment of Costs and Expenses. Borrower agrees to pay on demand all expenses of Lender (including the reasonable fees (on a solicitor and his own client basis) and out-of-pocket expenses of counsel to Lender and of local counsel, if any, who may be retained by counsel to Lender) in connection with (i) the negotiation, preparation, execution and delivery of this Agreement and of each other Loan Document, including schedules and exhibits, and any amendments, waivers, consents, supplements or other modifications to this Agreement or any other Loan Document as may from time to time hereafter be required, whether or not the transactions contemplated hereby are consummated; and (ii) the filing, recording, refiling or re-recording of the Debenture and/or any personal property security legislation financing statements relating thereto and all amendments, supplements and modifications to any thereof and any and all other documents or instruments of further assurance required to be filed or recorded or refiled or re-recorded by the terms hereof or of the Debenture or the Debenture Pledge Agreement; and (iii) the preparation and review of the form of any document or instrument relevant to this Agreement or any other Loan Document. Borrower further agrees to pay, and to save Lender harmless from all liability for, any stamp or other Taxes which may be payable in connection with the execution or delivery of this Agreement, or any other Loan Documents or the borrowings hereunder. Borrower also agrees to reimburse Lender upon demand for all reasonable out-of-pocket expenses (including counsel fees (on a solicitor and his own client basis) and legal expenses) incurred by Lender in connection with (A) the negotiation of any restructuring or "work-out", whether or not consummated, of any Obligations and (B) the enforcement of any Obligations. 12.4 Indemnification. In consideration of the execution and delivery of this Agreement by Lender and the extension of the Commitment, Borrower hereby indemnifies, exonerates and holds Lender and each of its officers, directors, employees and agents (collectively, the "Indemnified Parties") free and harmless from and against any and all actions, causes of action, suits, claims, losses, costs, liabilities and damages, and expenses incurred in connection therewith (irrespective of whether any such Indemnified Party is a party to the action for which indemnification hereunder is sought), including reasonable legal fees (on a solicitor and his own client basis) and disbursements (collectively, the "Indemnified Liabilities"), incurred by the Indemnified Parties or any of them as a result of, or arising out of, or relating to (i) any transaction financed or to be financed in whole or in part, directly or indirectly, with the proceeds of any Loan; (ii) the entering into and performance of this Agreement and any other Loan Document by any of the Indemnified Parties (including any action brought by or on behalf of Borrower or any of its Subsidiaries as the result of any determination by Lender pursuant to Article 5 not to fund any Loan) other than costs, expenses and taxes incurred or accruing to Lender in the ordinary course of performing its responsibilities and recovering income which have not otherwise been specified as being the responsibility of Borrower; (iii) any investigation, litigation or proceeding related to any environmental cleanup, remediation, audit, compliance assessments, fines or other matter relating to the protection of the Environment or the Release of any Hazardous Material in connection with, or related to, the Subject 62 Interests; (iv) the presence on or under, or the Release from, any of the Subject Interests of any Hazardous Material (including any losses, liabilities, damages, injuries, costs, expenses or claims asserted or arising under any Environmental Law), regardless of whether caused by, or within the control of, Borrower or its Subsidiaries, if any, (v) any material breach of any representation or warranty by Borrower or any of its Subsidiaries, if any, contained in this Agreement or any other Loan Document to which such Person is a party; (vi) the receipt by an Affiliate of Borrower of any Subject Hydrocarbons or the ownership or purported ownership of the Subject Interests; (vii) any Event of Default; (viii) any costs, expenses or liabilities incurred by Lender arising from Lender providing any services under Section 7.4; (ix) any costs, expenses or liabilities incurred by Lender arising from, in respect of or in connection with Borrower's obligations to any owner of royalty interests on the Subject Interests; (x) any obligation, liability, contingent or otherwise, costs or expenses for brokers' or finders' fees relating to Borrower or any of its Subsidiaries in respect of the matters provided for in any of the Loan Documents, or (xi) the failure of Borrower to perform any of its material agreements or obligations set forth in this Agreement or in the other Loan Documents, and whether through an act or omission of an Indemnified Party or otherwise, and whether or not arising out of the sole, joint or concurrent negligence, fault or strict liability of any Indemnified Party, except for any such Indemnified Liabilities arising for the account of a particular Indemnified Party by reason of the relevant Indemnified Party's gross negligence or willful misconduct, provided, that, it is the intention of the Parties that the indemnified parties be indemnified in the case of their own ordinary negligence but excluding gross negligence and willful misconduct, provided further that the indemnities set forth in subsections (i), (ii), (v), (vi), (vii), (viii), (ix), (x) and (xi) to the extent not related to any losses, liabilities, damages, injuries, costs, expenses or claims asserted or arising in connection with any Environmental Law shall only be in effect from the Effective Date until the date which is one (1) year following the date on which the unconditional and irrevocable payment in full in cash of all accrued and outstanding monetary Loan Obligations is received by Lender and the termination or expiration of the Commitment. This indemnity shall apply, without limitation, to any Indemnified Liability imposed upon any Indemnified Party as a result of any Applicable Law. The Indemnified Parties, and their respective successors and assigns, shall have the right to defend against any such claims, employing counsel therefor and, unless furnished with reasonable indemnity, they or any of them shall have the right to pay or compromise and adjust all such claims. If and to the extent that the foregoing undertaking may be unenforceable for any reason, Borrower hereby agrees to make the maximum contribution to the payment and satisfaction of each of the Indemnified Liabilities which is permissible under Applicable Law. 12.5 Survival. The obligations of Borrower under Sections 12.3 and 12.4 shall in each case survive any termination of this Agreement, the payment in cash of all accrued and outstanding monetary Loan Obligations and the termination or expiration of the Commitment. The representations and warranties made by Borrower in this Agreement and in each other Loan Document shall survive the execution and delivery of this Agreement and each such other Loan Document. 63 12.6 Inconsistency. To the extent that there is any inconsistency or ambiguity between the provisions of this Agreement and any other Loan Document, the provisions of this Agreement will govern to the extent necessary to eliminate such inconsistency or ambiguity. 12.7 Reimbursable Expenses. While not required, if Lender performs any of the covenants of Borrower, pays any amounts in respect thereof or suffers any loss, cost or expense as a result of the failure of Borrower to timely perform any covenant or make any such payment, any such cost or expense incurred by Lender in respect thereof shall constitute a Reimbursable Expense and will be considered a subsequent principal advance under this Agreement, subject to the Interest Rate. 12.8 Severability. Any provision of this Agreement or any other Loan Document which is prohibited or unenforceable in any jurisdiction shall, as to such provision and such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of this Agreement or such Loan Document or affecting the validity or enforceability of such provision in any other jurisdiction. 12.9 Headings. The various headings of this Agreement and of each other Loan Document are inserted for convenience only and shall not affect the meaning or interpretation of this Agreement or such other Loan Document or any provisions hereof or thereof. 12.10 Limitation on Liability. Lender's recourse as to the payment if principal and interest under the agreement is limited to the assets of Borrower and any other Obligor to the extent its or their assets are pledged, changed or mortgaged in favour of Lender unless certain actions of Borrower or any such other Obligor, including fraud, material misrepresentation, gross negligence and like actions, hinder or interfere with Lender's rights in the Property of Borrower and such other Obligors as set forth in the Loan Documents. 12.11 Intentions of the Parties. Nothing herein contained shall be construed to constitute either Party (under Applicable Law or for tax purposes) in partnership with the other Party. 12.12 Governing Law; Entire Agreement. This Agreement and each other Loan Document shall each be deemed to be a contract made under and governed by the laws of the Province of Alberta. 12.13 Successors and Assigns. This Agreement shall be binding upon and shall inure to the benefit of the Parties and their respective successors and permitted assigns; provided, however, that Borrower may not assign or transfer its rights or obligations hereunder without the prior written consent of Lender. Lender shall have the right to syndicate, sell or assign any portion of its Commitment Amount to any one or more Persons. In the event of such syndication, sale or assignment, Borrower shall, subject to the preceding limitations, execute and deliver all such agreements, documents and instruments as Lender may reasonably request to effect and recognize such syndication, sale or assignment. Any 64 syndication, sale or assignment as provided above, shall not require the consent of Borrower. 12.14 Effect of Syndication. To the extent that Lender sells or assigns any portion of its Commitment Amount pursuant to Section 12.13 and such new Lender has, or new Lenders have, as the case may be, executed and delivered to Borrower and Lender an agreement evidencing the same, Lender will be relieved and forever discharged of any and all of its covenants and obligations under the Loan Documents in respect of that portion of its Commitment Amount so sold or assigned from and after the date of such agreement and Borrower's recourse under the Loan Documents in respect of such portion so sold or assigned from and after the date of such agreement will be to such new Lender or new Lenders only, as the case may be, and their successors and assigns. 12.15 Participations. Lender may at any time sell to one or more financial institutions or other Persons (each of such financial institutions and other Persons being herein called a "Participant") participating interests in any of the Loans, commitments, or other interests of Lender hereunder, provided, however, that: (a) no participation contemplated in this Section 12.15 will relieve Lender from its commitments or its other obligations hereunder or under any other Document; (b) Lender will remain solely responsible for the performance of its Commitment and such other obligations; (c) no Participant will be entitled to require Lender to take or refrain from taking any action hereunder or under any other Loan Document; and (d) Borrower will not be required to pay any amount hereunder that is greater than the amount which it would have been required to pay had no participating interest been sold. 12.16 Maximum Rate of Return. Notwithstanding any provision herein to the contrary, in no event will the aggregate "interest" (as defined in section 347 of the Criminal Code (Canada)) payable under this Agreement and the other Loan Documents exceed the maximum effective annual rate of interest on the "credit advanced" (as defined in that section 347) permitted under that section 347 and, if any payment, collection or demand pursuant to this Agreement in respect of "interest" (as defined in that section 347) is determined to be contrary to the provisions of that section 347, such payment, collection or demand will be deemed to have been made by mutual mistake of Borrower and Lender and the amount of such payment or collection will be refunded to Borrower. For purposes of this Agreement and the other Loan Documents, the effective annual rate of interest will be determined in accordance with generally accepted actuarial practices and principles over the term of the Agreement on the basis of annual compounding of the lawfully permitted rate of interest and, in the event of dispute, a certificate of a Fellow of the Canadian Institute of Actuaries appointed by Lender will be prima facie evidence, for the purposes of such determination. 65 12.17 Waiver of Judgment Interest Act (Alberta). To the extent permitted by Applicable Law, the provisions of the Judgment Interest Act (Alberta) will not apply to the Loan Documents and are hereby expressly waived by Borrower. 12.18 Deemed Reinvestment Not Applicable. The principle of deemed reinvestment of interest will not apply to any interest calculation under the Loan Documents, and the rates of interest stipulated in this Agreement and the other Loan Documents are intended to be nominal rates and not effective rates or yields. 12.19 Confidentiality. Lender agrees that it (i) will maintain the confidentiality of all non-public information received from Borrower obtained pursuant to the terms of this Agreement or any other Loan Document in accordance with safe and sound business practices, and (ii) will not use such confidential information for any purpose other than in connection with this Agreement; provided, however, that this restriction shall not apply to information which (A) has at the particular time in question entered the public domain, or has been independently developed without the use or incorporation of any non-public information provided to Lender by Borrower by Lender other than through disclosure by Lender in violation of this Section 12.19, (B) is required to be disclosed by Applicable Law or by any order, rule, regulation or legal process (whether valid or invalid) of any court or Governmental Agency, (C) is furnished to any purchaser or prospective purchaser of participations, assignments or other interests in any Loan or Commitment that has executed and delivered to Borrower an agreement containing terms substantially similar to this Section 12.19 and reasonably acceptable to Borrower, to keep such information confidential, or (D) is disclosed to Lender's examiners, Affiliates, outside auditors, outside lenders to Lender, counsel and other professional advisors who have a need for such information in connection with this Agreement or in connection with their relationship with Lender and who are advised of the confidential nature of such information. As used in this Section, the term "Lender" shall refer not only to the Persons designated as such in Section 1.1, but also to each director, Affiliate, officer, agent, counsel, employee and representative of such Person. Notwithstanding any other provisions of this Agreement, the terms of this Section 12.19 shall survive the termination of this Agreement for a period of one (1) year. 12.20 Other Transactions. Nothing contained herein shall preclude Lender from engaging in any transaction, in addition to those contemplated by this Agreement or any other Loan Document, with Borrower or any of its Affiliates in which Borrower or such Affiliate is not restricted hereby from engaging with any other Person. 12.21 Forum Selection and Consent to Jurisdiction. Any litigation based hereon, or arising out of, under, or in connection with, this Agreement or any other Loan Document, or any course of conduct, course of dealing, statements (whether verbal or written) or actions of Lender or Borrower or any other Obligor shall be brought and maintained exclusively in the courts of the Province of Alberta; provided, however, that any suit seeking enforcement against the Subject Interests or other Property may be brought, at Lender's option, in the courts of any jurisdiction where such Subject Interests or other Property may be found. Borrower, hereby expressly and irrevocably submit to the jurisdiction of the courts of the Province of Alberta for 66 the purpose of any such litigation as set forth above and irrevocably agrees to be bound by any judgment rendered thereby in connection with such litigation. Borrower further irrevocably consents, to the service of process by registered mail, postage prepaid, or by personal service within or outside of the Province of Alberta. Borrower hereby expressly and irrevocably waives, to the fullest extent permitted by Applicable Law, any objection which they may have or hereafter may have to the laying of venue of any such litigation brought in any such court referred to above and any claim that any such litigation has been brought in an inconvenient forum. To the extent that Borrower has or hereafter may acquire any immunity from jurisdiction of any court of from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution or otherwise) with respect to itself or its Property, Borrower hereby irrevocably waives such immunity in respect of its Obligations under this Agreement and the other Loan Documents. 12.22 Waiver of Jury Trial. Borrower hereby knowingly, voluntarily and intentionally waives any rights they may have to a trial by jury in respect of any litigation based hereon, or arising out of, under, or in connection with, this Agreement or any other Loan Document, or any course of conduct, course of dealing, statements (whether verbal or written) or actions of Lender or Borrower or any other Obligor. Borrower acknowledges and agrees that they have received full and sufficient consideration for this provision (and each other provision of each other Loan Document to which it is a Party) and that this provision is a material inducement for Lender entering into this Agreement and each such other Loan Document. 12.23 No Oral Agreements. This Agreement and the other Loan Documents represent the final agreement between the Parties and may not be contradicted by evidence of prior, contemporaneous or subsequent oral agreements of the Parties. There are no unwritten oral agreements between the Parties. 12.24 Execution in Counterparts, Effectiveness. This Agreement may be executed by the Parties in several counterparts (including by facsimile transmission), each of which shall be deemed to be an original and all of which shall constitute together but one and the same agreement. This Agreement shall become effective when counterparts hereof executed on behalf of Borrower and Lender (or notice thereof satisfactory to Lender) shall have been received by Lender and notice thereof shall have been given by Lender to Borrower. 67 IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective officers thereunto duly authorized as of the day and year first above written. GREY WOLF EXPLORATION INC. By: Name: Robert L. G. Watson Title: Chairman, President and Chief Executive Officer Address: 1600 Bow Valley Square III 255 - 2nd Street S.W. Calgary, Alberta T2P 3G6 Attention: Robert L. G. Watson Telephone No.:(403) 262-1949 Telecopy No.: (403) 262-1969 MIRANT CANADA ENERGY CAPITAL, LTD. By: Name: Rob Lindermanis Title: Managing Director Address: Suite 300 440 - 2nd Avenue SW Calgary, Alberta T2P 5E9 Attention: Rob Lindermanis, Managing Director Telephone No.:(403) 218-1075 Telecopy No.: (403) 218-1575 with a copy to Mirant Americas Energy Capital, L.P. at: Address: Two Allen Center, Ste. 2890 1200 Smith Street Houston, Texas 77002 Attention: Dave Stewart, Managing Director Telephone No.(713) 276-1902 Telecopy No.: (713) 276-1990 SCHEDULE I Description of Subject Interests [Borrower to provide] SCHEDULE II Use of Proceeds Repayment of Canadian Imperial Bank of Commerce** $_____________ General Corporate Purposes $_____________ TOTAL: $_____________ [**Indicates amounts funded with initial Loan] SCHEDULE III Insurance Requirements Lender (Mirant Canada Energy Capital, Ltd.) must be listed as "sole loss payee as to first party claims" and "additional insured" on each of the policies required below. Requirements for: GREY WOLF EXPLORATION INC. SCHEDULE IV Disclosure Schedule NIL SCHEDULE V Pension Plan Grey Wolf Exploration Inc. has established a group Registered Retirement Savings Plan where the employee is invited to participate in the program by contributing from 1 - 5% of their annual gross salary to a RRSP portfolio of their choice. Deductions are taken each pay period and contributed to Merrill Lynch Canada, the group plan administrator, on a monthly basis. The Company will match the employees' contribution on a monthly basis. Company contributions credited to the employee shall vest immediately. Upon reaching the yearly maximum contribution limit as set by legislation, both the employee's and the company's contributions will be deposited to a non-RRSP account. SCHEDULE VI List of Transportation Agreements [To be provided] SCHEDULE VII Financing Lease Arrangements [To be provided] SCHEDULE VIII Title Deficiencies [To be provided] EXHIBIT A [Form of] Loan Request Mirant Canada Energy Capital, Ltd. Suite 300, 440 - 2nd Avenue S.W. Calgary, Alberta T2P 5E9 Attention: Managing Director GREY WOLF EXPLORATION INC. Gentlemen and Ladies: This Loan Request is delivered to you pursuant to Section 2.3 of the Credit Agreement, dated as of December 20, 2001 (together with all amendments, if any, from time to time made thereto, the "Credit Agreement"), between Grey Wolf Exploration Inc., an Alberta corporation (the "Borrower"), and you. Unless otherwise defined herein or the context otherwise requires, terms used herein have the meanings provided in the Credit Agreement. Borrower hereby requests that a Loan be made in the aggregate principal amount of $______________ on ______________, 20_____. Borrower hereby acknowledges that, pursuant to Article 5 of the Credit Agreement, each of the delivery of this Loan Request and the acceptance by Borrower of the proceeds of the Loans requested hereby constitute a representation and warranty by Borrower that, on the date of such Loans, and before and after giving effect thereto and to the application of the proceeds therefrom, all statements set forth in Article 6 of the Credit Agreement are true and correct in all material respects. Borrower agrees that if prior to the time of the Loan requested hereby any matter certified to herein by it will not be true and correct at such time as if then made, it will immediately so notify you. Borrower certifies that no Default of Event of Default has occurred and is continuing. Except to the extent, if any, that prior to the time of the Loan requested hereby you shall receive written notice to the contrary from Borrower, each matter certified to herein shall be deemed once again to be certified as true and correct at the date of such Loan as if then made. Please wire transfer the proceeds of the Loan to the Collateral Account. Borrower has caused this Loan Request to be executed and delivered, and the certification and warranties contained herein to be made, by its ____________ this ____ day of _____________, 200__. GREY WOLF EXPLORATION INC. By: -------------------------------------------- Name: Title: EXHIBIT B [Form of] Opinion of Borrower's Counsel [see attached] EXHIBIT C-1 [Form of] Debenture [see attached] EXHIBIT C-2 [Form of] Debenture Pledge Agreement [see attached] EXHIBIT D [Form of] Override Royalty Agreement No. 1 [see attached] EXHIBIT E [Form of] Override Royalty Agreement No. 2 [see attached] EXHIBIT F [Form of] ISDA Master Agreement [see attached] EXHIBIT G Development Plan [see attached] EXHIBIT H [Form of] Environmental Certificate [see attached] EXHIBIT I [Form of] Title Certificate [see attached] EX-10 4 mirantorri1.txt Exhibit 10.22 FIRST OVERRIDING ROYALTY AGREEMENT THIS AGREEMENT dated as of the 20th day of December, 2001 BETWEEN: GREYWOLF EXPLORATION INC., having an office in Calgary, Alberta (hereinafter called "Greywolf") - and - MIRANT CANADA ENERGY CAPITAL, LTD., having an office in Calgary, Alberta (hereinafter called "Mirant") WHEREAS the Parties wish to enter into this agreement to provide for the reservation and granting of the Overriding Royalty; NOW THEREFORE in consideration of the premises, covenants and agreements of the Parties, the Parties hereby covenant and agree as follows: 1. DEFINITIONS Each capitalized term in this Agreement will have the meaning given to it in the Royalty Procedure, and, in addition: (a) "Agreement" and "Head Agreement" means this Overriding Royalty Agreement and all schedules attached hereto. (b) "Permitted Encumbrances" has the meaning ascribed thereto in Section 4. (c) "Royalty Lands" means all lands in which the Royalty Owner currently owns a working interest including, without limitation, those lands described in Schedule "A". (d) "Royalty Owner" means Mirant. (e) "Royalty Payor" means Greywolf. (f) "Royalty Payor's Working Interest" means the working interest of the Royalty Payor as described in Schedule "A". (g) "Royalty Procedure" means the standard form 1997 CAPL Overriding Royalty Procedure including the elections and amendments, all attached hereto as Schedule "B". 2 2. SCHEDULES The following schedules are attached hereto and made part of this Agreement: (a) Schedule "A" which describes the Title Documents, the Royalty Lands, and the Royalty Payor's Working Interest; (b) Schedule "B" which is the Royalty Procedure Elections and Amendments; (c) Schedule "C" which is the Royalty Procedure; and (d) Schedule "D" which is the form of Royalty Lands Addition Schedule. 3. ROYALTY (a) The Royalty Payor hereby grants, conveys, bargains, sells, assigns, transfers and sets over to the Royalty Owner an overriding royalty interest in and to the Royalty Lands (the "Overriding Royalty") TO HAVE AND TO HOLD the Overriding Royalty, together with all and singular, all rights, privileges, options, heredita-ments, and appurtenances thereto in any way belonging to the Royalty Owner, its successors and assigns forever, subject to the terms, conditions, exceptions, reservations, covenants and agreements herein set forth. (b) The Overriding Royalty shall be calculated, administered and otherwise dealt with in accordance with this Agreement. (c) The Overriding Royalty shall become effective on the Effective Date and shall encumber the Royalty Lands in the manner set forth in this Agreement. (d) For the purposes of Subclause 2.01 A of the Royalty Procedure, the Overriding Royalty will be multiplied by the Royalty Payor's Working Interest percentage of production after deducting: (i) all applicable Crown royalties in accordance with the Regulations; (ii) all applicable freehold royalties as identified in Schedule "A"; and (iii) all applicable royalties payable to third parties encumbering the Royalty Lands as of the date hereof (other than those payable in respect of Petroleum Substances as described in (i) and (ii) above) identified in Schedule "A". (e) The Overriding Interest is and the Parties intend for it to constitute an interest in land which shall burden and run with any transfer of all or any portion of the Royalty Lands. 3 4. TITLE REPRESENTATION Royalty Payor represents and warrants that the Overriding Royalty granted and conveyed hereby is free and clear of any mortgages, deeds of trust, voluntary or contractual liens, pledges, security interests, charges, conditional sales or other title retention documents, or other encumbrances or burdens other than those in favor of Royalty Payor or as expressly set forth under the heading "Encumbrances" on Schedule A (the "Permitted Encumbrances"), and the Royalty Payor hereby binds itself, its successors and assigns to warrant and forever defend the title to the Overriding Royalty herein granted, conveyed, assigned, and transferred unto Royalty Owner, its successors and assigns, against the lawful claims and demands of every person whomsoever claiming or to claim the same or any part thereof, by, through or under the Royalty Payor. 5. ADDITION OF ROYALTY LANDS (a) Subject to Clauses 5(b) and (c) hereof, the Parties may from time to time add additional lands to the Royalty Lands by executing two copies of a completed Royalty Lands Addition Schedule in the form attached hereto as Schedule "D". (b) In the event that the parties elect ALTERNATE A of Section 3 of any Royalty Lands Addition Schedule, the Royalty Procedure Elections and Amendments attached hereto as Schedule "B" shall apply to the lands added to the Royalty Lands hereby. (c) In the event that the Parties elect ALTERNATE B of Section 3 of any Royalty Lands Addition Schedule, the Parties shall also complete the separate Alternate Elections and Amendments Form in the form as provided in Section 3B of the Royalty Lands Addition Schedule. Any such elections or amendments to the Royalty Procedure shall only apply to the Royalty Lands set forth in the Royalty Lands Addition Schedule to which they are attached and shall have no effect upon the royalty applicable to any other Royalty Lands subject to this Agreement. 6. ADDRESSES FOR NOTICES The Parties' addresses for notices for this Agreement are: Royalty Payor: Grey Wolf Exploration, Inc. Suite 1600, Bow Valley Square III 255 - 5th Avenue S.W. Calgary, AB T2P 3G6 Attention: Vice President, Land and Contracts Royalty Owner: Mirant Canada Energy Capital, Ltd. 4 #300, 440 - 2nd Ave. S.W. Calgary, AB T2P 5E9 Attention: Robert Lindermanis, Managing Director 7. FURTHER ASSURANCES From time to time, each party will, at the reasonable request of the other party, take all action, do all such acts and execute and deliver all agreements, instruments, documents or other writings desired or required by such other party in connection with the registration of its interest in this Agreement or any other agreement, document, instrument or other writing to be executed and delivered pursuant hereto at any public registry or otherwise and take all action and execute and deliver all such further agreements, instruments, documents or other writings reasonably desired or required by such other party so as to fully perform or carry out the terms, intents or purposes of this Agreement. 8. INVALIDITY OF PROVISIONS If any of the provisions of this Agreement are determined to be invalid, illegal or unenforceable in any respect, the validity, legality or enforceability of the remaining provisions shall not in any way be affected or impaired thereby. 9. TIME Time shall be of the essence in this Agreement. 10. SUCCESSORS AND ASSIGNS This Agreement will be binding upon and will enure to the benefit of the parties hereto and their respective successors and permitted assigns. 11. COUNTERPART EXECUTION This Agreement and any document or instrument to be executed and delivered by the parties hereunder or in connection herewith may be executed and delivered in separate counterparts and delivered by one party to the other by facsimile, each of which when so executed and delivered shall be deemed an original and all such counterparts shall together constitute one and the same agreement, if this Agreement or any such document or instrument is delivered by facsimile, the party so delivering this Agreement or such document or instrument shall within a reasonable time after such delivery deliver an originally executed copy to the other. 12. GOVERNING LAW; ATTORNMENT; ETC. (a) This Agreement shall be governed by, and construed and enforced in accordance with, the applicable laws, other than conflict of laws rules, prevailing in the Province of Alberta. 5 (b) The parties irrevocably: (i) submit and attorn to the non-exclusive jurisdiction of the courts of the Province of Alberta for all matters arising out of or relating to this Agreement, or any of the transactions contemplated hereby; (ii) waive all right to object to jurisdiction of such courts in any legal action or proceeding relative to this Agreement or the transactions contemplated hereby or execution of any judgment, order or decree issued in or as a result of any such action, suit or proceeding which they may now or hereafter have by reason of domicile or otherwise; (iii) waive any objection to the laying of venue in such courts of any of the aforesaid actions, suits or proceedings arising out of or in connection with this Agreement or the transactions contemplated hereby; (iv) waive and agree not to plead or claim that any action, suit or proceeding in such courts has been brought in an inconvenient forum; and (v) waive any right they may have to, or to apply for, trial by jury in connection with any matter, action, proceeding, claim or counterclaim arising out of or relating to this Agreement or any of the transactions contemplated hereby. (c) Each party shall appoint and maintain an attorney in Alberta for service of process in respect of actions, suits or proceedings arising out of or in connection with this Agreement or the transactions contemplated hereby and advise the other party from time to time of the name and address of such attorney, provided that it shall not change the attorney so appointed or terminate the appointment unless (and no change or termination shall be effective until) they have previously given written advice to the other party of a new attorney in Alberta for such purpose, in which case this proviso shall again apply in respect of the new attorney so appointed. 13. REFERENCES AND HEADINGS The references "hereunder", "herein" and "hereof" refer to the provisions of this Agreement, and references to Articles and Sections herein refer to articles, sections, or subsections of this Agreement. Any reference to time shall refer to Mountain Standard Time or Mountain Daylight Saving Time during the respective intervals in which each is in force in the Province of Alberta. The headings of the Articles, Sections, Schedules and any other headings, captions or indices herein are inserted for convenience of reference only and shall not be used in any way in construing or interpreting any provision hereof. 6 14. SINGULAR/PLURAL; DERIVATIVES Whenever the singular or masculine or neuter is used in this Agreement, it shall be interpreted as meaning the plural or feminine or body politic or corporate, and vice versa, as the context requires. Where a term is defined herein, a capitalized derivative of such term shall have a corresponding meaning unless the context otherwise requires. IN WITNESS WHEREOF the Parties hereto have executed this Agreement as of the day and year first above written. GREY WOLF EXPLORATION INC. MIRANT CANADA ENERGY CAPITAL, LTD. Per: Per: ------------------------------ ---------------------------- Robert L.G. Watson Robert Lindermanis Chairman, President & CEO Managing Director SCHEDULE "A" attached to and forming part of a First Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTYLANDS, TITLE DOCUMENTS AND ROYALTY PAYOR'S WORKING INTEREST The following _____ pages comprise Schedule A. SCHEDULE "B" attached to and forming part of a First Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTY PROCEDURE ELECTIONS AND AMENDMENTS 1. Effective Date (Subclause 1.01 (b)) - December 20, 2001 2. Quantification of Overriding Royalty (Subclause 2.01 A) for crude oil - 2.5 % for all other Petroleum Substances - Alternate 1 will apply (Specify 1 or 2) If Alternate 1 applies: 2.5 % If Alternate 2 applies: N/A % in (i) and N/A % in (ii) 3. Royalty Payor's Allowed Deductions If Overriding Royalty Not Taken In Kind (Subclause 2.04 B if applicable) Alternate(s) 1 only _________ /2 only ______________/ 1 and 2/ neither 1 nor 2____________ 4. Royalty Owner's Rights Upon Surrender (Subclause 2.08) will |X| / will not (Specify) apply. 5. Other Amendments: Deletion - Clause 2.03 D (b). Clause 2.03 (D)(b) is deleted in its entirety. Amendment - Clause 2.03 C. Clause 2.03 C is amended by deleting the word "Payor's" in the first sentence and replacing same with the word "Owner's". Addition - Clause 2.04. Clause 2.04 is amended by adding the words "other than the costs of removing basic sediment and water where such charges are material" to the end of the first sentence. Deletion - Clause 7.00. Clause 7.00 is deleted in its entirety. SCHEDULE "C" attached to and forming part of a First Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTY PROCEDURE (The following 10 pages comprises Schedule "C") SCHEDULE "D" attached to and forming part of a First Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTY LANDS ADDITION SCHEDULE (The following 3 pages comprises Schedule "D") ROYALTY LANDS ADDITION SCHEDULE WHEREAS Greywolf Exploration, Ltd. ("Greywolf") and Mirant Canada Energy Capital, Ltd. ("Mirant") are parties to that certain Overriding Royalty Agreement dated December 18, 2001 (the "Royalty Agreement"). AND WHEREAS the Royalty Agreement provides for the addition of lands and petroleum and natural gas rights owned by the Royalty Payor to the Royalty Lands by execution of this Royalty Lands Addition Schedule. AND WHEREAS Greywolf, as Royalty Payor and Mirant, as Royalty Owner wish to add additional lands and petroleum and natural gas rights to the Royalty Lands. NOW THEREFORE Greywolf and Mirant hereby agree as follows: DEFINITIONS 1. Unless otherwise indicated, terms used in this Schedule shall have the meanings ascribed to them in the Royalty Agreement. ADDITION OF LANDS 2. The following lands (the "Additional Lands") are hereby added as Royalty Lands pursuant to Article 4 of the Royalty Agreement: - -------------------------------------------------------------------------------- Royalty Lands | Title Documents | Royalty Payor's Working | | Interest - -------------------------------------------------------------------------------- | | | | - -------------------------------------------------------------------------------- ELECTIONS AND AMENDMENTS 3. Pursuant to Sections 4(a) and 4(b) of the Royalty Agreement, Greywolf and Mirant hereby elect as follows: ALTERNATE A (pursuant to Section 4(a) of the Royalty Agreement): - --------- --------- Init. Schedule B of the Royalty Agreement (with the exception of Section 1 Effective Date which shall be , 200 ) shall govern the royalty applicable to the Additional Lands. - --------- -- Init. ALTERNATE B (pursuant to Section 4(b) of the Royalty Agreement). - --------- --------- Init. The following Royalty Procedure Elections and Amendments shall govern the royalty applicable to the Additional Lands: - --------- Init. 2 1. Effective Date (Subclause 1.01 (b)) - _____________ , 200_ 2. Quantification of Overriding Royalty (Subclause 2.01 A) for crude oil -_____ % for all other Petroleum Substances - Alternate_____ will apply (Specify 1 or 2) If Alternate 1 applies:_______ % If Alternate 2 applies:_______ % in (i) and______ % in (ii) - - 3. Royalty Payor's Allowed Deductions If Overriding Royalty Not Taken In Kind (Subclause 2.04 B if applicable) Alternate(s) 1 only_______ / 2 only _______ / 1 and 2 ________/ neither 1 nor 2________(Specify Alternate) If Alternate 2 applies, deductions must not be greater than o% of the Market Price. 4. Royalty Owner's Rights Upon Surrender (Subclause 2.08) will / will not (Specify) apply. 5. Other Amendments (if any) EXECUTED by the parties hereto on the dates indicated below: GREYWOLF EXPLORATION INC. MIRANT CANADA ENERGY CAPITAL, LTD. per: per: ------------------------------ --------------------------- Name: Name: Position: Position: Date: Date: EX-10 5 mirantorri2.txt Exhibit 10.23 SECOND OVERRIDING ROYALTY AGREEMENT THIS AGREEMENT dated as of the 20th day of December, 2001 BETWEEN: GREYWOLF EXPLORATION INC., having an office in Calgary, Alberta (hereinafter called "Greywolf") - and - MIRANT CANADA ENERGY CAPITAL, LTD., having an office in Calgary, Alberta (hereinafter called "Mirant") WHEREAS the Parties wish to enter into this agreement to provide for the reservation and granting of the Overriding Royalty; NOW THEREFORE in consideration of the premises, covenants and agreements of the Parties, the Parties hereby covenant and agree as follows: 1. DEFINITIONS Each capitalized term in this Agreement will have the meaning given to it in the Royalty Procedure, and, in addition: (a) "Agreement" and "Head Agreement" means this Overriding Royalty Agreement and all schedules attached hereto. (b) "Permitted Encumbrances" has the meaning ascribed thereto in Section 4. (c) "Royalty Lands" means all lands in which the Royalty Owner currently owns a working interest including, without limitation, those lands described in Schedule "A". (d) "Royalty Owner" means Mirant. (e) "Royalty Payor" means Greywolf. (f) "Royalty Payor's Working Interest" means the working interest of the Royalty Payor as described in Schedule "A". (g) "Royalty Procedure" means the standard form 1997 CAPL Overriding Royalty Procedure including the elections and amendments, all attached hereto as Schedule "B". 2 2. SCHEDULES The following schedules are attached hereto and made part of this Agreement: (a) Schedule "A" which describes the Title Documents, the Royalty Lands, and the Royalty Payor's Working Interest; (b) Schedule "B" which is the Royalty Procedure Elections and Amendments; (c) Schedule "C" which is the Royalty Procedure; and (d) Schedule "D" which is the form of Royalty Lands Addition Schedule. 3. ROYALTY (a) The Royalty Payor hereby grants, conveys, bargains, sells, assigns, transfers and sets over to the Royalty Owner an overriding royalty interest in and to the Royalty Lands (the "Overriding Royalty") TO HAVE AND TO HOLD the Overriding Royalty, together with all and singular, all rights, privileges, options, heredita-ments, and appurtenances thereto in any way belonging to the Royalty Owner, its successors and assigns forever, subject to the terms, conditions, exceptions, reservations, covenants and agreements herein set forth. (b) The Overriding Royalty shall be calculated, administered and otherwise dealt with in accordance with this Agreement. (c) The Overriding Royalty shall become effective on the Effective Date and shall encumber the Royalty Lands in the manner set forth in this Agreement. (d) For the purposes of Subclause 2.01 A of the Royalty Procedure, the Overriding Royalty will be multiplied by the Royalty Payor's Working Interest percentage of production after deducting: (i) all applicable Crown royalties in accordance with the Regulations; (ii) all applicable freehold royalties as identified in Schedule "A"; and (iii) all applicable royalties payable to third parties encumbering the Royalty Lands as of the date hereof (other than those payable in respect of Petroleum Substances as described in (i) and (ii) above) identified in Schedule "A". (e) The Overriding Interest is and the Parties intend for it to constitute an interest in land which shall burden and run with any transfer of all or any portion of the Royalty Lands. 3 4. TITLE REPRESENTATION Royalty Payor represents and warrants that the Overriding Royalty granted and conveyed hereby is free and clear of any mortgages, deeds of trust, voluntary or contractual liens, pledges, security interests, charges, conditional sales or other title retention documents, or other encumbrances or burdens other than those in favor of Royalty Payor or as expressly set forth under the heading "Encumbrances" on Schedule A (the "Permitted Encumbrances"), and the Royalty Payor hereby binds itself, its successors and assigns to warrant and forever defend the title to the Overriding Royalty herein granted, conveyed, assigned, and transferred unto Royalty Owner, its successors and assigns, against the lawful claims and demands of every person whomsoever claiming or to claim the same or any part thereof, by, through or under the Royalty Payor. 5. ADDITION OF ROYALTY LANDS (a) Subject to Clauses 5(b) and (c) hereof, the Parties may from time to time add additional lands to the Royalty Lands by executing two copies of a completed Royalty Lands Addition Schedule in the form attached hereto as Schedule "D". (b) In the event that the parties elect ALTERNATE A of Section 3 of any Royalty Lands Addition Schedule, the Royalty Procedure Elections and Amendments attached hereto as Schedule "B" shall apply to the lands added to the Royalty Lands hereby. (c) In the event that the Parties elect ALTERNATE B of Section 3 of any Royalty Lands Addition Schedule, the Parties shall also complete the separate Alternate Elections and Amendments Form in the form as provided in Section 3B of the Royalty Lands Addition Schedule. Any such elections or amendments to the Royalty Procedure shall only apply to the Royalty Lands set forth in the Royalty Lands Addition Schedule to which they are attached and shall have no effect upon the royalty applicable to any other Royalty Lands subject to this Agreement. 6. ADDRESSES FOR NOTICES The Parties' addresses for notices for this Agreement are: Royalty Payor: Grey Wolf Exploration Inc. Suite 1600, Bow Valley Square III 255 - 5th Avenue S.W. Calgary, AB T2P 3G6 Attention: Vice President, Land and Contracts Royalty Owner: Mirant Canada Energy Capital, Ltd. 4 #300, 440 - 2nd Ave. S.W. Calgary, AB T2P 5E9 Attention: Robert Lindermanis, Managing Direcetor 7. FURTHER ASSURANCES From time to time, each party will, at the reasonable request of the other party, take all action, do all such acts and execute and deliver all agreements, instruments, documents or other writings desired or required by such other party in connection with the registration of its interest in this Agreement or any other agreement, document, instrument or other writing to be executed and delivered pursuant hereto at any public registry or otherwise and take all action and execute and deliver all such further agreements, instruments, documents or other writings reasonably desired or required by such other party so as to fully perform or carry out the terms, intents or purposes of this Agreement. 8. INVALIDITY OF PROVISIONS If any of the provisions of this Agreement are determined to be invalid, illegal or unenforceable in any respect, the validity, legality or enforceability of the remaining provisions shall not in any way be affected or impaired thereby. 9. TIME Time shall be of the essence in this Agreement. 10. SUCCESSORS AND ASSIGNS This Agreement will be binding upon and will enure to the benefit of the parties hereto and their respective successors and permitted assigns. 11. COUNTERPART EXECUTION This Agreement and any document or instrument to be executed and delivered by the parties hereunder or in connection herewith may be executed and delivered in separate counterparts and delivered by one party to the other by facsimile, each of which when so executed and delivered shall be deemed an original and all such counterparts shall together constitute one and the same agreement, if this Agreement or any such document or instrument is delivered by facsimile, the party so delivering this Agreement or such document or instrument shall within a reasonable time after such delivery deliver an originally executed copy to the other. 12. GOVERNING LAW; ATTORNMENT; ETC. (a) This Agreement shall be governed by, and construed and enforced in accordance with, the applicable laws, other than conflict of laws rules, prevailing in the Province of Alberta. 5 (b) The parties irrevocably (i) submit and attorn to the non-exclusive jurisdiction of the courts of the Province of Alberta for all matters arising out of or relating to this Agreement, or any of the transactions contemplated hereby; (ii) waive all right to object to jurisdiction of such courts in any legal action or proceeding relative to this Agreement or the transactions contemplated hereby or execution of any judgment, order or decree issued in or as a result of any such action, suit or proceeding which they may now or hereafter have by reason of domicile or otherwise; (iii) waive any objection to the laying of venue in such courts of any of the aforesaid actions, suits or proceedings arising out of or in connection with this Agreement or the transactions contemplated hereby; (iv) waive and agree not to plead or claim that any action, suit or proceeding in such courts has been brought in an inconvenient forum; and (v) waive any right they may have to, or to apply for, trial by jury in connection with any matter, action, proceeding, claim or counterclaim arising out of or relating to this Agreement or any of the transactions contemplated hereby. (c) Each party shall appoint and maintain an attorney in Alberta for service of process in respect of actions, suits or proceedings arising out of or in connection with this Agreement or the transactions contemplated hereby and advise the other party from time to time of the name and address of such attorney, provided that it shall not change the attorney so appointed or terminate the appointment unless (and no change or termination shall be effective until) they have previously given written advice to the other party of a new attorney in Alberta for such purpose, in which case this proviso shall again apply in respect of the new attorney so appointed. 13. REFERENCES AND HEADINGS The references "hereunder", "herein" and "hereof" refer to the provisions of this Agreement, and references to Articles and Sections herein refer to articles, sections, or subsections of this Agreement. Any reference to time shall refer to Mountain Standard Time or Mountain Daylight Saving Time during the respective intervals in which each is in force in the Province of Alberta. The headings of the Articles, Sections, Schedules and any other headings, captions or indices herein are inserted for convenience of reference only and shall not be used in any way in construing or interpreting any provision hereof. 6 14. SINGULAR/PLURAL; DERIVATIVES Whenever the singular or masculine or neuter is used in this Agreement, it shall be interpreted as meaning the plural or feminine or body politic or corporate, and vice versa, as the context requires. Where a term is defined herein, a capitalized derivative of such term shall have a corresponding meaning unless the context otherwise requires. IN WITNESS WHEREOF the Parties hereto have executed this Agreement as of the day and year first above written. GREYWOLF EXPLORATION INC. MIRANT CANADA ENERGY CAPITAL, LTD. Per: Per: ----------------------------------- ----------------------------------- Robert L.G. Watson Robert Lindermanis Chairman, President & CEO Managing Director SCHEDULE "A" attached to and forming part of a Second Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTYLANDS, TITLE DOCUMENTS AND ROYALTY PAYOR'S WORKING INTEREST The following ______ pages comprise Schedule A. SCHEDULE "B" attached to and forming part of a Second Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTY PROCEDURE ELECTIONS AND AMENDMENTS 1. Effective Date (Subclause 1.01 (b)) - December 20, 2001 2. Quantification of Overriding Royalty (Subclause 2.01 A) for crude oil - 2.5 % ------- for all other Petroleum Substances - Alternate 1 will apply (Specify 1 or 2) ------ If Alternate 1 applies: 2.5 % ---------- If Alternate 2 applies: N/A % in (i) and N/A % in (ii) --------- -------- 3. Royalty Payor's Allowed Deductions If Overriding Royalty Not Taken In Kind (Subclause 2.04 B if applicable) Alternate(s) 1 only______ / 2 only /_______ 1 and 2 ___________/ neither 1 nor 2____________ 4. Royalty Owner's Rights Upon Surrender (Subclause 2.08) will |X| / will not (Specify) apply. 5. Other Amendments: Deletion - Clause 2.03 D (b). Clause 2.03 (D)(b) is deleted in its entirety. Amendment - Clause 2.03 C. Clause 2.03 C is amended by deleting the word "Payor's" in the first sentence and replacing same with the word "Owner's". Addition - Clause 2.04. Clause 2.04 is amended by adding the words "other than the costs of removing basic sediment and water where such charges are material" to the end of the first sentence. Amendment - Clause 5.01. Clause 5.01 is amended by deleting the words "either the Royalty Owner or" from the last line. Addition - Clause 5.02. The following is added as Clause 5.02: The Royalty Owner may not assign its interest under the Head Agreement without the written consent of the Royalty Payor which consent may be withheld at the discretion of the Royalty Payor. Deletion - Clause 7.00. Clause 7.00 is deleted in its entirety. SCHEDULE "C" attached to and forming part of a Second Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Ltd. ROYALTY PROCEDURE (The following 10 pages comprises Schedule "C") SCHEDULE "D" attached to and forming part of a Second Overriding Royalty Agreement dated the 20th day of December, 2001 between Greywolf Exploration Inc. and Mirant Canada Energy Capital, Inc. ROYALTY LANDS ADDITION SCHEDULE (The following 3 pages comprises Schedule "D") ROYALTY LANDS ADDITION SCHEDULE WHEREAS Greywolf Exploration, Inc. ("Greywolf") and Mirant Canada Energy Capital, Inc. ("Mirant") are parties to that certain Overriding Royalty Agreement dated December 18, 2001 (the "Royalty Agreement"). AND WHEREAS the Royalty Agreement provides for the addition of lands and petroleum and natural gas rights owned by the Royalty Payor to the Royalty Lands by execution of this Royalty Lands Addition Schedule. AND WHEREAS Greywolf, as Royalty Payor and Mirant, as Royalty Owner wish to add additional lands and petroleum and natural gas rights to the Royalty Lands. NOW THEREFORE Greywolf and Mirant hereby agree as follows: DEFINITIONS 1. Unless otherwise indicated, terms used in this Schedule shall have the meanings ascribed to them in the Royalty Agreement. ADDITION OF LANDS 2. The following lands (the "Additional Lands") are hereby added as Royalty Lands pursuant to Article 4 of the Royalty Agreement: - ----------------------- ---------------------------- --------------------------- Royalty Lands Title Documents Royalty Payor's Working Interest - ----------------------- ---------------------------- --------------------------- - ----------------------- ---------------------------- --------------------------- - ----------------------- ---------------------------- --------------------------- ELECTIONS AND AMENDMENTS 3. Pursuant to Sections 4(a) and 4(b) of the Royalty Agreement, Greywolf and Mirant hereby elect as follows: ALTERNATE A (pursuant to Section 4(a) of the Royalty Agreement): - --------- --------- Init. Schedule B of the Royalty Agreement (with the exception of Section 1 Effective Date which shall be ______, 200_ ) shall govern the royalty applicable to the Additional Lands. - --------- Init. ALTERNATE B (pursuant to Section 4(b) of the Royalty Agreement). - --------- --------- Init. The following Royalty Procedure Elections and Amendments shall govern the royalty applicable to the Additional Lands: - --------- Init. 2 1. Effective Date (Subclause 1.01 (b)) -_______________ , 200_ 2. Quantification of Overriding Royalty (Subclause 2.01 A) for crude oil -____ % for all other Petroleum Substances - Alternate______ will apply (Specify 1 or 2) ------ If Alternate 1 applies:____& If Alternate 2 applies:____ % in (i) and____ % in (ii) 3. Royalty Payor's Allowed Deductions If Overriding Royalty Not Taken In Kind (Subclause 2.04 B if applicable) Alternate(s) 1 only______ / 2 only /_____ 1 and 2 /________ neither 1 nor 2 (Specify Alternate) If Alternate 2 applies, deductions must not be greater than o% of the Market Price. 4. Royalty Owner's Rights Upon Surrender (Subclause 2.08) will / will not (Specify) apply. 5. Other Amendments (if any) EXECUTED by the parties hereto on the dates indicated below: GREYWOLF EXPLORATION INC. MIRANT CANADA ENERGY CAPITAL, LTD. per: per: ------------------------------ ---------------------------- Name: Name: Position: Position: Date: Date: -----END PRIVACY-ENHANCED MESSAGE-----