10-K 1 abp10k2003.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, 2003 [ ]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. [ X ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act) [ ] Yes [X] No The aggregate market value of the voting stock (which consists solely of shares of common stock) held by nonaffiliates of the registrant as June 30, 2003, based upon the closing per share price of $1.08, was approximately $30,917,000 on such date. The number of shares of the issuer's common stock, par value $.01 per share, outstanding as of March 9, 2004 was 36,267,337 shares of which 29,068,400 shares were held by non-affiliates. Documents Incorporated by Reference: Portions of the registrant's Proxy Statement relating to the 2004 Annual Meeting of Shareholders to be held on May 21, 2004 have been incorporated by reference herein (Part III). ABRAXAS PETROLEUM CORPORATION FORM 10-K TABLE OF CONTENTS PART I Page Item 1. Business............................................................5 General............................................................5 Markets and Customers..............................................6 Risk Factors.......................................................7 Regulation of Crude Oil and Natural Gas Activities................13 Canadian Royalty Matters..........................................15 Environmental Matters ...........................................17 Title to Properties...............................................19 Employees.........................................................19 Item 2. Properties.........................................................19 Primary Operating Areas...........................................19 Exploratory and Developmental Acreage.............................20 Productive Wells..................................................21 Reserves Information..............................................21 Crude Oil, Natural Gas Liquids and Natural Gas Production and Sales Price .....................................23 Drilling Activities...............................................24 Office Facilities.................................................24 Other Properties..................................................25 Item 3. Legal Proceedings.................................................25 Item 4. Submission of Matters to a Vote of Security Holders...............25 Item 4A. Executive Officers of Abraxas.....................................25 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.................................27 Market Information................................................27 Holders...........................................................27 Dividends.........................................................27 Recent Sales of Unregistered Securities...........................27 Item 6. Selected Financial Data...........................................28 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................28 General........................................................28 Results of Operations..........................................31 Liquidity and Capital Resources................................35 Critical Accounting Policies...................................41 New Accounting Pronouncements..................................44 Item 7A. Quantitative and Qualitative Disclosures about Market Risk........46 Item 8. Financial Statements and Supplementary Data.......................47 3 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.....................................48 Item 9A. Controls and Procedures..........................................48 PART III Item 10. Directors and Executive Officers of the Registrant ..............48 Item 11. Executive Compensation............................................49 Item 12. Security Ownership of Certain Beneficial Owners and Management....49 Item 13. Certain Relationships and Related Transactions....................49 Item 14. Principal Accountant Fees and Services ...........................49 PART IV Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................49 SIGNATURES.......................................................54 4 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 or what we "intend" to do, 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 document is generally located in the material set forth under the headings "Risk Factors," "Business," and "Management's Discussion and Analysis of Financial Condition and Results of Operations" 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 regarding our operations include, among others, the following: o our high debt level; o our ability to raise capital; o our limited liquidity; o economic and business conditions; o price and availability of alternative fuels; o political and economic conditions in oil producing countries, especially those in the Middle East; o our success in development, exploitation and exploration activities; o planned capital expenditures; o prices for crude oil and natural gas; o declines in our production of crude oil and natural gas; o our acquisition and divestiture activities; o results of our hedging activities; and o other factors discussed elsewhere in this document. PART I Item 1. Business General Abraxas Petroleum Corporation is an independent energy company engaged primarily in the acquisition, development, exploitation and production of crude oil and natural gas. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of our historical acquisition activities, we believe that we have a substantial inventory of low risk exploitation and development opportunities, the successful completion of which is critical to the maintenance and growth of our current production levels. In this report, 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 or natural gas liquids and MBbls is used to designate one thousand barrels of crude oil or natural gas liquids. 5 Our principal areas of operation are Texas and western Canada. At December 31, 2003, we owned interests in 263,730 gross acres (183,354 net acres), and operated properties accounting for approximately 88% of our PV-10, affording us substantial control over the timing and incurrence of operating and capital expenditures. At December 31, 2003 estimated total proved reserves were 121.1 Bcfe with an aggregate PV-10 of $216.8 million. During 2003, we continued exploitation activities on our U.S. and Canadian properties. We participated in the drilling of 24 gross (11.8 net) wells with 23 gross (11.3 net) being successful. The Company invested $18.3 million in capital spending on these activities during 2003. At the end of 2003, as a result of these activities, our average daily production was approximately 24 MMcfe per day which represented a 26% increase from the daily production rate at the beginning of the year (excluding production from the Canadian properties sold in January 2003). In January 2003, we completed the following restructuring transactions: o The closing of the sale of the capital stock of our wholly-owned subsidiaries Canadian Abraxas Petroleum Limited, referred to herein as Canadian Abraxas, and Grey Wolf Exploration Inc., referred to herein as Old Grey Wolf, to a Canadian royalty trust for approximately $138 million. o The closing of a new senior credit agreement consisting of a term loan facility of $4.2 million and a revolving credit facility of up to $50 million with an initial borrowing base of $49.9 million, of which $42.5 million was used to fund the exchange offer described below and the remaining availability funded the continued development of our existing crude oil and natural gas properties. o The closing of an exchange offer, pursuant to which Abraxas paid $264 in cash and issued $610 principal amount of new 11 1/2 % Secured Notes due 2007, Series A, referred to herein as New Notes, and 31.36 shares of Abraxas common stock for each $1,000 in principal amount of the outstanding 11 1/2 % Senior Secured Notes due 2004, Series A, and 11 1/2 % Senior Notes due 2004, Series D, issued by Abraxas and Canadian Abraxas, which were tendered and accepted in the exchange offer. An aggregate of approximately $179.9 million in principal amount of the notes were tendered in the exchange offer and the remaining $11.1 million of notes not tendered were redeemed. o The repayment of Abraxas' 12? % Senior Secured Notes due 2003, principal amount of $63.5 million, plus accrued interest. o The repayment of Old Grey Wolf's senior secured credit facility with Mirant Canada Energy Capital Ltd. (Mirant Canada Facility) in the amount of approximately $46.3 million. As a result of these transactions, we reduced the principal amount of our total outstanding long-term debt from approximately $300 million at December 31, 2002 to approximately $156.4 million at January 23, 2003 ($184.6 million at December 31, 2003) and reduced our annual cash interest payment from approximately $34 million to approximately $4 million, assuming that, as required under the senior credit agreement, Abraxas continues to issue additional notes in lieu of cash interest payments on the New Notes. On February 23, 2004, we entered into an amendment to our existing senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date for these credit facilities is February 1, 2007. We have included a detailed summary of our amended senior credit agreement in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Long-Term Indebtedness - Senior Credit Agreement". 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 6 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 effect 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 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 historical hedging activities. Substantially all of our crude oil and natural gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2003 three purchasers accounted for approximately 80% of our United States crude oil and natural gas sales and three customers accounted for approximately 91% of our crude oil and natural gas sales in Canada. 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 realize 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 historical hedging activities. Risk Factors Risks Related to Our Company Our reduced operating cash flow resulting from the sale of Canadian Abraxas and Old Grey Wolf may put significant strain on our liquidity and cash position. Our reduced operating cash flow and resulting limited liquidity has caused us, and the limitations imposed by our senior credit agreement and the New Notes will cause us, to reduce capital expenditures, including exploitation and development projects. These reductions will limit our ability to replenish our depleting reserves, which could negatively impact our cash flow from operations and results of operations in the future. In addition, under the terms of the New Notes, we are required, to the extent permitted, to pay down debt under our senior credit agreement and, if permitted, the New Notes, with our cash flow which is not required to pay our capital expenditures or make cash interest and tax payments. The effects of our reduced operating cash flow will be exacerbated by our high level of debt, which will affect our operations in several important ways, including: o A portion of our cash flow from operations could be required to make principal and interest payments on our outstanding indebtedness and may not be available for other purposes, including developing our properties; 7 o The covenants contained in the indenture governing the New Notes and in the senior credit agreement will limit our ability to borrow additional funds or to dispose of assets or use the proceeds of any asset sales and may affect our flexibility in planning for, and reacting to, changes in our business; and 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. Our limited liquidity and restrictions on uses of cash dictated by both our senior credit agreement and the New Notes, combined with our high debt levels, may hinder our ability to satisfy the substantial capital requirements related to our operations. The success of our future operations will require us to make substantial capital expenditures for the exploitation, development and production of crude oil and natural gas. Under the terms of the senior credit agreement and the New Notes, Abraxas is subject to cash and expenditures covenants including limitations on capital expenditures. These limitations will have the effect of limiting our ability to develop our crude oil and natural gas properties because much of our cash flow may be used for debt service. As a result, our ability to replace production may be limited. You should read the discussion under "Our ability to replace production with new reserves is highly dependent on acquisitions or successful development and exploration activities" for more information regarding the risks associated with limitations on our ability to develop our crude oil and natural gas properties. Hedging transactions may limit our potential gains. Under the terms of the senior credit agreement, we are required to maintain commodity price hedging positions on not less than 40% and not more than 75% of our estimated production for a rolling six-month period. As of December 31, 2003 we had floors in place as follows: Time Period Notional Quantities Price ----------------------------------------------------------------------------- March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50 2004 production per day March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00 production per day March 1, 2004 - April 30, 2004 500 Bbls of crude oil Floor of $22.00 production per day May 2004 2,000 MMbtu of natural gas Floor of $4.00 production per day May 2004 500 Bbls of crude oil Floor of $22.00 production per day June 2004 800 Bbls of crude oil Floor of $22.00 production per day July 2004 2,000 MMbtu of natural gas Floor of $4.00 production per day July 2004 500 Bbls of crude oil Floor of $22.00 production per day Subsequent to year-end, we have entered into additional agreements similar to those scheduled above (floors) in volume amounts sufficient to reach the 40% threshold required by our senior credit agreement. We anticipate continuing to purchase similar floors in the future to satisfy our requirements under the senior credit agreement. We cannot assure you that our hedging 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, and have in the past limited, additional revenues from price increases. In addition, such transactions may expose us to risks of financial loss under certain circumstances, such as: o production being less than expected; or 8 o price differences between delivery points for our production and those in our hedging agreements increasing. In 2001, 2002 and 2003, we experienced hedging losses of $12.1 million, $3.2 million and $842,000, respectively. Our ability to replace production with new reserves is highly dependent on acquisitions or successful development and exploitation 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, exploitation 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. 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. 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. The terms of our senior credit agreement and the new notes limit our capital expenditures which will further limit our ability to replenish our reserves and replace production. Further, in addition to the effects of our limited liquidity, our operations may be curtailed, delayed or cancelled by other factors, such as title problems, weather, compliance with governmental regulations, mechanical problems or shortages or delays in the delivery of equipment. We cannot assure you that our exploration and development activities will result in increases in reserves. Use of our net operating loss carryforwards may be limited. At December 31, 2003, Abraxas had, subject to the limitation discussed below, $100.6 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2003 through 2022 if not utilized. In connection with the January 2003 transactions described in Note 2, in Notes to Consolidated Financial Statements, Item 8, certain of the loss carryforwards were utilized. As to a portion of the U.S. net operating loss carryforwards, the amount of such carryforwards that we can use annually is limited under U.S. tax law. Additionally, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, Abraxas has established a valuation allowance of $99.1 million and $76.1 million for deferred tax assets at December 31, 2002 and 2003, respectively. Crude oil and natural gas prices and their volatility could adversely affect our revenue, cash flows, profitability and growth. Our revenue, cash flows, 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 because most of our production and reserves are natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may have ceiling limitation write-downs if prices decline. For example, during the second quarter of 2002, we had a ceiling limitation write down of approximately $116.0 million. 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 Middle East; and 9 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 causing a ceiling limitation write-down; o increasing our dependence on external sources of capital to meet our liquidity requirements; o reducing our borrowing base under our senior credit agreement; and o impairing our ability to obtain needed equity capital. 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, as adjusted for asset retirement obligations. If net capitalized costs of crude oil and natural gas properties, as adjusted for asset retirement obligations, 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 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. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. We have incurred ceiling limitation writedowns in the past. At June 30, 2002, for example, we recorded a ceiling limitation writedown of $116 million. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. 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 period 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 10 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 annual 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, 2003. The sales prices as of such date used for purposes of such estimates were $31.03 per Bbl of crude oil, $27.19 per Bbl of NGLs and $5.05 per Mcf of natural gas. This compares with $29.69 per Bbl of crude oil, $18.89 per Bbl of NGLs and $3.79 per Mcf of natural gas as of December 31, 2002. These estimates also assume that we will make future capital expenditures of approximately $50.4 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 have experienced recurring net losses. The following table shows the losses we had in 1998, 1999, 2001 and 2002: Years Ended December 31, 1998 1999 2001 2002 ---- ---- ---- ---- Net loss $(84.0) $(36.7) $(19.7) $ (118.5) While we had net income in 2000 of $8.4 million, if the significant gain on the sale of an interest in a partnership were excluded, we would have experienced a net loss for the year of ($25.5) million. Similarly, while we had net income of $55.9 million in 2003, if the gain on the sale of our Canadian subsidiaries were excluded, we would have experienced a net loss for the year of ($13.0) million. We cannot assure you that we will become profitable in the future. 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 Canadian operations are subject to the risks of currency fluctuations and in some instances economic and political developments. We conduct 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 any 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 three-year employment contract with Abraxas commencing on December 21, 1999, 11 which automatically renews thereafter for successive one-year periods unless Abraxas gives 120 days notice prior to the expiration of the original term or any extension thereof of its intention not to renew the employment agreement. 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. Risks Related to Our Industry Our operations are subject to numerous risks of crude oil and natural gas drilling and production activities. Our 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: o title problems, o weather conditions, o compliance with governmental requirements, and o mechanical difficulties or shortages or delays in the delivery of drilling rigs 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. 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 12 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. Our crude oil and natural gas operations are subject to various U.S. federal, state and local and Canadian federal and provincial governmental 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. 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, our 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 13 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. Currently, the Federal Energy Regulatory Commission (the "FERC), requires each interstate pipeline to, among other things, "unbundle" 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 are not required to remain "merchants" of natural gas, and most of the interstate pipeline companies have become "transporters only," although many have affiliated marketers Transportation pipeline availability and shipping 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 FERC 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. 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 important policy initiatives which could significantly affect the marketing of natural gas in the United States. Most of these initiatives are intended to enhance competition in natural gas markets. FERC rules encouraging "spin downs," or the breakout of unregulated gathering activities from regulated transportation services, 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 certain facilities by their new, unregulated owners. As to all of the FERC initiatives, the ongoing, or, in some instances, preliminary and evolving nature makes it impossible at this time to predict their ultimate impact on our business. However, we do not believe that any FERC initiatives will affect us any differently than other natural gas producers and marketers with which we compete. FERC decisions involving onshore facilities are 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 in the past 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 FERC decisions create 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. 14 In summary, all of the FERC activities related to the transportation of natural gas result 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 where we own producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas. These include 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 or service 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 FERC. 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") prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS prohibits 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 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 reference prices, well productivity, geographical location, field discovery date and the type and 15 quality of the petroleum product produced. From time to time the governments of Alberta and British Columbia, the provinces where almost all of New Grey Wolf's production is located, 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. All of New Grey Wolf's production is from oil and gas rights which have been granted by the Provinces. The Province of Alberta requires the payment from lessees of oil and gas rights of annual rental payments as well as royalty payments. 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. An 8,000 cubic meters exemption is available to production from a well that has not produced for a 12-month period prior to January 31, 1993 or 24 consecutive months following such date. 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 classifies conventional crude oil into three categories, being Old Oil, New Oil and Third Tier Oil. Each have a base royalty rate of 10%. The rate caps on the categories are 25% for oil from crude oil pools discovered after September 30, 1992, being the Third Tier Oil, 30% for oil from pools or pool extensions discovered after April 1, 1974, from wells drilled or deepened after October 31, 1991 or from reactivated wells and which are not Third Tier Oil, and 35% for Old Oil. 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 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 meter (CDN $15.90 per Bbl) and 35% for prices above CDN $210 per cubic meter (CDN $33.38 per Bbl). 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. 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. British Columbia also classifies conventional crude oil into the three categories of Old Oil, New Oil and Third Tier Oil. The amount payable as a royalty in 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 a discovery well may be exempt from the payment of a royalty for the first 36 months of production to a maximum production of 72,024 Bbls. The royalty payable on natural gas is determined by a sliding scale based on a classification of the gas based on whether it is conservation gas (gas associated with marketed oil production) and by drilling and land lease date and on a reference price which is the greater of the amount obtained by the producer and at prescribed minimum price. Conservation gas has a minimum royalty of 8%. The royalty rate ranges from between 9% and 27% for wells drilled on lands issued after May 31, 1998 and before January 1, 2003 and completed within 5 years of the date the lands were issued and between 12% and 27% for wells spudded after May 31, 1998 on lands where rights had been issued as of May 31, 1998. 16 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 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 there from, and are usually causes of action based on negligence, trespass, nuisance, strict liability and fraud. 17 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 believe that we have obtained and are in compliance with all material environmental permits, authorizations and approvals. All of our oil and gas wells will require proper plugging and abandonment when they are no longer producing. We post bonds with most regulatory agencies to ensure compliance with our plugging responsibility. Plugging and abandonment operations and associated reclaimation of the surface production site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing. 18 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 9, 2004, we had 46 full-time employees in the United States, including 3 executive officers, 3 non-executive officers, 1 petroleum engineer, 1 geologist, 5 managers, 1 landman, 11 administrative and support 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 9, 2004, New Grey Wolf had 11 full-time employees, including 4 executive officers, 1 non-executive officer, 2 geologists and, 4 technical and clerical personnel in Canada. Available Information Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments filed with the Securities and Exchange Commission are available on our web site at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports are filed. 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, 2003 located in those two regions. We operate 94% of our wells in Texas. During 2003, we drilled a total of six new wells (3.73 net) in Texas with a 100% success rate. Operations in South Texas are concentrated along the Edwards trend in Live Oak and DeWitt Counties, the Frio/Vicksburg trend in San Patricio County and the Wilcox trend in Goliad County. In total in South Texas we own an average 93% working interest in 43 wells with average production of 239 net Bbls of crude oil and NGLs and 6,210 net Mcf of natural gas per day for the year ended December 31, 2003. As of December 31, 2003 we had estimated net proved reserves in South Texas of 28.6 Bcfe (82% natural gas) with a PV-10 of $57.7 million, 70% of which was attributable to proved developed reserves. Our West Texas operations are concentrated along the deep Devonian/Montoya/Ellenberger formations and shallow Cherry Canyon sandstones in Ward County and in the Sharon Ridge Clearfork Field in Scurry County. In September 2000, we entered into a farmout agreement with EOG Resources Inc. whereby EOG earned a 75% working interest in Abraxas' then existing Ward County Montoya acreage by paying Abraxas $2.5 million and paying 100% of the cost of the first five wells, the last of which came on line in December 2002. Two wells were drilled in 2003 in which Abraxas was responsible for its pro rata share of drilling and development cost. The farmout agreement terminated in early January 2004 and accordingly, EOG is obligated to reassign all unearned acreage to Abraxas. 19 In total in West Texas we own an average 74% working interest in 158 wells with average daily production of 338 net Bbls of crude oil and NGLs and 6,887 net Mcf of natural gas per day for the year ended December 31, 2003. As of December 31, 2003, we had estimated net proved reserves in West Texas of 71.1 Bcfe (80% natural gas) with a PV-10 of $103.6 million, 60% of which was attributable to proved developed reserves. Wyoming We currently hold over 60,000 contiguous acres in the Powder River Basin in east central Wyoming. The Company has drilled and operates 5 wells in Converse and Niobrara counties that were completed in the Turner and Niobrara formations. We own a 100% working interest in these wells that produced an average of 31 net barrels of crude oil per day in 2003. As of December 31, 2003 we had estimated net proved producing reserves in Wyoming of 68,669 barrels of crude oil with a PV-10 of $280,843. Western Canada We own properties in western Canada, consisting primarily of natural gas reserves and undeveloped acreage in the provinces of Alberta and British Columbia. Our Alberta properties are in two concentrated areas; the Caroline field, 60 miles northwest of Calgary and the Peace River Arch area in northwestern Alberta. We entered into a farmout agreement with PrimeWest in connection with the sale of Canadian Abraxas and Old Grey Wolf in January of 2003 to jointly develop these areas in the future. Our other Canadian operations are located in the Ladyfern area of northeast British Columbia. During 2003, we drilled a total of 18 new wells (8.1 net) with a 95% success rate. As of December 31, 2003 New Grey Wolf had estimated net proved reserves of 21.0 Bcfe (77% natural gas) with a PV-10 of $55.2 million of which 76% was attributable to proved developed reserves. For the year ended December 31, 2003, the Canadian properties produced an average of approximately 111 net Bbls of crude oil and NGLs per day and 2,328 net Mcf of natural gas per day. 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, 2003: Developed and Undeveloped Acreage ---------------------------------------------------------------- As of December 31, 2003 ---------------------------------------------------------------- Developed Acreage (1) Undeveloped Acreage (2) --------------------------------- ------------------------------ Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4) --------------- --------------- --------------- -------------- Canada 18,238 9,075 155,246 93,866 Texas 23,671 18,978 5,864 4,692 Wyoming 3,200 3,200 57,431 53,519 N. Dakota - - 80 24 --------------- ------------------------------ -------------- Total 45,109 31,253 218,621 152,101 =============== ============================== ============== --------------- (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, 2003: 20 Productive Wells (1) ------------------------------------------------- As of December 31, 2003 ---------------- ------------------------------------------------- State/Country Crude Oil Natural Gas ---------------- ------------------------- ----------------------- Gross(2) Net(3) Gross(2) Net(3) ------------- ----------- ----------- ----------- Canada 29.0 5.1 205.0 17.0 Texas 140.5 112.6 60.5 44.7 Wyoming 5.0 5.0 18.0 - N. Dakota 1.0 - - - ------------- ----------- ----------- ----------- Total 175.5 122.7 283.5 61.7 ============= =========== =========== =========== ------------ (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. Reserves Information The crude oil and natural gas reserves of the U.S. operations only have been estimated as of January 1, 2004, January 1, 2003, and January 1, 2002, by DeGolyer and MacNaughton, of Dallas, Texas. The reserves of the Canadian operations as of January 1, 2004 and January 1, 2003 have been estimated by DeGolyer and MacNaughton, and the reserves as of January 1, 2002 were estimated by McDaniel and Associates Consultants Ltd. of Calgary, Alberta. The January 1, 2003 reserves attributable to the Canadian properties which were sold in connection with the sale of Canadian Abraxas and Old Grey Wolf were estimated internally. The January 1, 2004 reserves related to an override which was retained by New Grey Wolf were estimated internally. Crude oil and natural gas reserves, and the estimates of the present value of future net revenues there-from, 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 there from. 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, 2003 and January 1, 2004: 21 Estimated Proved Reserves -------------------------------------- Proved Proved Total Developed Undeveloped Proved ------------ -------------- ---------- As of January 1, 2002 (1) 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 As of January 1, 2003 (2) Crude oil (MBbls) 1,782 1,317 3,099 NGLs (MBbls) 1,222 284 1,506 Natural gas (MMcf) 90,374 48,458 138,832 As of January 1, 2004 Crude oil (MBbls) 2,051 1,578 3,629 NGLs (MBbls) 263 242 505 Natural gas (MMcf) 52,398 43,885 96,284 ------------------ (1)Reserves as of January 1, 2002 include 138 MBbls of crude oil, 2,257 MBbls of NGLs and 80,289MMcf of natural gas that were sold in connection with the sale of Canadian Abraxas and Old Grey Wolf in January 2003. (2)Reserves as of January 1, 2003 include 67 MBbls of crude oil, 1,079 MBbls of NGLs, and 47,066 MMcf of natural gas that were sold in connection with the sale of Canadian Abraxas and Old Grey Wolf in January 2003. 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. Because we use the full cost method to account for our crude oil and natural gas operations, we are susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. At June 30, 2002, we incurred a ceiling test writedown of approximately $116.0 million. A ceiling test writedown does not impact cash flow from operating activities but does reduce our stockholders' equity and reported earnings. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. For more information regarding the full cost method of accounting, you should read the information under "Management's Discussion and Analysis of Financial Condition and Results of Operation - Critical Accounting Policies." 22 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, 2003. The average sales prices as of such date used for purposes of such estimates were $31.03 per Bbl of crude oil, $27.19 per Bbl of NGLs and $5.05 per Mcf of natural gas. It is also assumed that we will make future capital expenditures of approximately $50.4 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, 2003.
2001 (1) 2002 (1) 2003 (1) ----------------- ---------------- ----------------- Crude oil production (Bbls) 454,063 292,264 251,567 Natural gas production (Mcf) 17,495,598 15,452,721 6,189,359 Natural gas liquids production (Bbls) 277,969 242,032 37,258 MMcfe 21,888 18,658 7,922 Average sales price per Bbl of crude oil $ 24.63 $ 24.34 $ 30.32 Average sales price per Mcf of natural gas (2) $ 3.20 $ 2.55 $ 4.78 Average sales price per Bbl of natural gas liquids $ 21.51 $ 17.94 $ 24.47 Average sales price per Mcfe $ 3.35 $ 2.72 $ 4.81 Average cost of production per Mcfe produced (3) $ 0.85 $ 0.82 $ 1.21 ------------------
(1)Includes production for 2001, 2002 and the first 23 days of 2003 for Canadian properties sold in January 2003. (2) Average sales prices are net of hedging activity. (3)Crude oil and natural gas were combined by converting crude oil and natural gas liquids to a Mcf equivalent on the basis of 1 Bbl of crude oil and natural gas liquid equals 6 Mcf of natural gas. Production costs include direct operating costs, ad valorem taxes and gross production taxes. 23 Drilling Activities Thefollowing table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended December 31, 2003:
2001 2002 2003 ----------------------------- ----------------------------- ------------------------------- Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) ------------ ---------- ------------ ---------- ---------- -------- Exploratory(3) Productive(4) Crude oil - - 1.0 1.0 1.0 1.0 Natural gas 2.0 1.0 3.0 0.5 - - Dry holes(5) 1.0 .5 3.0 1.5 1.0 0.5 ------------ ---------- ------------ ---------- ---------- -------- Total 3.0 1.5 7.0 3.0 2.0 1.5 ============ ========== ============ ========== ========== ======== Development(6) Productive (4) Crude oil 2.0 2.0 - - 2.0 2.0 Natural gas 13.0 11.0 14.0 11.8 20.0 8.3 Dry holes (5) - - 1.0 1.0 - - ------------ ---------- ------------ ---------- ---------- -------- Total 15.0 13.0 15.0 12.8 22.0 10.3 ============ ========== ============ ========== ========== ======== ------------------
(1) A gross well is a well in which we own an interest. (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 9, 2004 we had five wells in process of drilling and completing, two in the U.S. and three in Canada. Office Facilities Our executive and administrative offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232, consisting of approximately 12,650 square feet leased until March 2006 at an aggregate base rate of $20,900 per month. We also have an office in Midland, Texas consisting of 570 square feet leased through October 2004 at an aggregate base rate of $380 per month. New Grey Wolf leases 7,350 square feet of office space in Calgary, Alberta, leased through December 2008 at an aggregate base rate of $13,400 US$ per month. 24 Other Properties We own 10 acres of land, an office building, workshop, warehouse and house in Sinton, Texas, 2.8 acres of land, an office building in Scurry County, Texas, 600 acres of fee land in Scurry County, Texas and 160 acres of land in Coke County, Texas. All three properties are used for the storage of tubulars and production equipment. We also own 25 vehicles which are used in the field by employees. We own 2 workover rigs, which are used for servicing our wells. Item 3. Legal Proceedings In 2001, Abraxas and Abraxas Wamsutter L.P. 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 Abraxas and Abraxas Wamsutter, L.P. related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by Abraxas and Abraxas Wamsutter, L.P. 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. Abraxas has filed an appeal. We believe these charges are without merit. We have established a reserve in the amount of $845,000, which represents our estimated share of the judgment. In 2003, Abraxas and Leam Drilling Systems each filed suit against the other relating to certain drilling services that Leam contracted to provide Abraxas. Abraxas believes that the services were provided in a grossly negligent manner and that Leam committed fraud. Leam has asserted that Abraxas failed to pay approximately $639,000 for services rendered. The cases are pending in Bexar County and Ward County, Texas. Additionally, from time to time, we are involved in litigation relating to claims arising out of its operations in the normal course of business. At December 31, 2003, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our operations. 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, 2003. 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 2004 annual meeting of shareholders and until his successor is duly elected and qualified. Robert L. G. Watson, age 53, 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 52, 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 25 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 42, 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. 26 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters Market Information Abraxas common stock began trading on the American Stock Exchange on August 18, 2000, under the symbol "ABP." The following table sets forth certain information as to the high and low bid quotations quoted for Abraxas' common stock on the American Stock Exchange. Period High Low 2002 First Quarter $ 1.70 $ 0.89 Second Quarter 1.41 0.52 Third Quarter 0.98 0.42 Fourth Quarter 0.80 0.52 2003 First Quarter $ 0.95 $ 0.55 Second Quarter 1.30 0.61 Third Quarter 1.11 0.82 Fourth Quarter 1.32 0.88 2004 First Quarter (Through March 9, 2004) $ 3.64 $ 1.29 Holders As of March 9, 2004, we had 36,267,337 shares of common stock outstanding and had approximately 1,597 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 indenture governing the New Notes and our senior credit agreement prohibits 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. Recent Sales of Unregistered Securities On January 23, 2003, we issued approximately $109.7 million in principal amount of New Notes and 5,642,699 shares of Abraxas common stock in connection with the exchange offer. These securities were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended, under Regulation D. The securities were offered and sold only to accredited investors and to no more than 35 non-accredited investors each of whom Abraxas believed had such knowledge and experience in financial and business matters that he or she was capable of evaluation of the merits and risks on the investment in the New Notes and shares of Abraxas common stock. On July 29, 2003 Abraxas acquired all of the shares of the capital stock of Wind River Resources Corporation which owned an airplane. The sole shareholder of Wind River was the Company's President. The consideration for the purchase was 106,977 shares of Abraxas common stock and $35,000 in cash. These securities were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended, under Section 4(2). 27 Item 6. Selected Financial Data The following selected financial data is 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" in Item 8.
Year Ended December 31, -------------------------------------------------------------------------------- 1999* 2000* 2001* 2002* 2003* ----- ----- ----- ----- ----- (Dollars in thousands except per share data) Total revenue $ 66,770 $ 76,600 $ 77,243 $ 54,320 $ 39,019 Net income (loss) $ (36,680) (3) $ 8,449 (2)$ (19,718) (4) $ (118,527) (1)$ 55,920 (5) Net income (loss) per common share - diluted $ (5.41) $ 0.26 $ (0.76) $ (3.95) $ 1.55 Weighted average shares outstanding - diluted (in thousands) 6,784 22,616 25,789 29,979 36,076 Total assets $ 322,284 $ 335,560 $ 303,616 $ 181,425 $ 126,437 Long-term debt, excluding current maturities $ 273,421 $ 266,441 $ 285,184 $ 236,943 $ 184,649 Total stockholders' equity (deficit) $ (9,505) $ (6,503) $ (28,585) $ (142,254) $ (72,203)
(1) Includes ceiling limitation write-down of $116.0 million. (2) Includes gain on sale of partnership interest of $34 million in 2000 and the reclassification of an extraordinary gain on debt extinguishment in 2000 to other income. (3) Includes ceiling limitation write-down of $19.1 million. (4) Includes ceiling test write-down of $2.6 million in 2001, based on subsequent (March 22, 2002) realized prices, related to our Canadian operations. (5) Includes gain on sale of foreign subsidiaries of $ 68.9 million in 2003. *Data includes Canadian Abraxas and Old Grey Wolf for 1999-2002 and for the first 23 days of 2003 which were sold in January 2003. 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" in Item 8. General We are an independent energy company engaged primarily in the acquisition, exploration, exploitation and production of crude oil and natural gas. Our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties. As a result of our historical acquisition activities, we believe that we have a substantial inventory of low risk exploitation and development opportunities, the successful completion of which is critical to the maintenance and growth of our current production levels. We have incurred net losses in three of the last five years, and there can be no assurance that operating income and net earnings will be achieved in future periods. 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; 28 o the availability of, and our ability to raise additional, 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 exploitation and development activity. Commodity Prices and Hedging Activities. Our results of operations are significantly affected by fluctuations in commodity prices. Price volatility in the natural gas market has remained prevalent in the last few years. In January 2001, the market price of natural gas was at its highest level in our operating history and the price of crude oil was also at a high level. However, over the course of 2001 and the beginning of the first quarter of 2002, prices again became depressed, primarily due to the economic downturn. Beginning in March 2002, commodity prices began to increase and continued higher through December 2003. Prices have remained strong during the first part of 2004. The table below illustrates how natural gas prices fluctuated over the course of 2002 and 2003. The table below contains the last three day average of NYMEX traded contracts price and the prices we realized during each quarter for 2002 and 2003, including the impact of our hedging activities.
Natural Gas Prices by Quarter (in $ per Mcf) ---------------------------------------------------------------------------------------------------- Quarter Ended ---------------------------------------------------------------------------------------------------- March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31, 2002 2002 2002 2002 2003 2003 2003 2003 ------------ ----------- ----------- ------------ ----------- ------------- ----------- ------------ Index $ 2.38 $ 3.36 $ 3.28 $ 3.99 $ 6.61 $ 5.51 $ 5.10 $ 4.60 Realized $ 2.21 $ 2.44 $ 2.08 $ 3.47 $ 5.13 $ 5.11 $ 4.50 $ 4.30
The NYMEX natural gas price on March 9, 2004 was $5.44 per Mcf. The table below contains the last three day average of NYMEX traded contracts price and the prices we realized during each quarter for 2002 and 2003.
Crude Oil Prices by Quarter (in $ per Bbl) ------------------------------------------------------------------------------------------------------- Quarter Ended ------------------------------------------------------------------------------------------------------- March 31, June 30, Sept. 30, Dec. 31, March 31, June 30, Sept. 30, Dec. 31, 2002 2002 2002 2002 2003 2003 2003 2003 ----------- ----------- ------------ -------------- ------------- ----------- ------------ ------------ Index $ 19.48 $ 26.40 $ 27.50 $ 28.29 $ 33.71 $ 29.87 $ 30.85 $ 29.64 Realized $ 16.64 $ 23.47 $ 23.47 $ 24.83 $ 33.22 $ 28.53 $ 29.52 $ 29.73
The NYMEX crude oil price on March 9, 2004 was $ 36.28 per Bbl. We seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. In 2001 and 2002, we experienced hedging losses of $12.1 million and $3.2 million, respectively. In October 2002, all of these hedge agreements expired. We made total payments over the term of these arrangements to various counterparties in the amount of $35.1 million. Under the terms of our senior credit agreement, we are required to maintain hedging positions with respect to not less than 40% nor more than 75% of our crude oil and natural gas production, on an equivalent basis, for a rolling six month period. As of December 31, 2003, we had the following hedges in place: Time Period Notional Quantities Price --------------------------------- ----------------------------- --------------- March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50 2004 production per day 29 March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00 production per day March 1, 2004 - April 30, 2004 500 Bbls of crude oil Floor of $22.00 production per day May 2004 2,000 Mmbtu of natural gas Floor of $4.00 production per day June 2004 500 Bbls of crude oil Floor of $22.00 production per day June 2004 800 Bbls of crude oil Floor of $22.00 production per day July 2004 2,000 Mmbtu of natural gas Floor of $4.00 production per day July 2004 500 Bbls of crude oil Floor of $22.00 production per day Subsequent to year-end we have entered into additional agreements similar to those scheduled above (floors) in volume amounts sufficient to reach the 40% threshold required by our senior credit agreement. The Company anticipates continuing to purchase similar floors in the future to satisfy our requirements under the senior credit agreement. Production Volumes. Because our proved reserves will decline as crude oil, natural gas and natural gas liquids are produced, unless we acquire additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploitation and development projects. For more information on the volumes of crude oil, natural gas liquids and natural gas we have produced during 2001, 2002 and 2003, please refer to the information under the caption "Results of Operations" below. We have budgeted $10 million for drilling expenditures in 2004. Under the terms of our senior credit agreement and our New Notes, we are subject to limitations on capital expenditures. As a result, we will be limited in our ability to replace existing production with new production and might suffer a decrease in the volume of crude oil and natural gas we produce. If crude oil and natural gas prices return to depressed levels or if our production levels continue to decrease, our revenues, cash flow from operations and financial condition will be materially adversely affected. For more information, see "Liquidity and Capital Resources - Current Liquidity Requirements" and "Future Capital Resources." Availability of Capital. As described more fully under "Liquidity and Capital Resources" below, our sources of capital are primarily cash on hand, cash from operating activities, funding under our senior credit agreement and the sale of properties. At March 9, 2004, we had approximately $14.0 million of availability under our senior credit agreement. We may also attempt to raise additional capital through the issuance of debt or equity securities although we cannot assure you that we will be successful in any such efforts. Borrowings and Interest. As a result of the financial restructuring we completed in January 2003, we reduced our indebtedness from approximately $300.4 million at December 31, 2002 to approximately $184.6 million at December 31, 2003. In addition, we decreased our cash interest expense from $34.2 million during 2002 to $4.3 million during 2003. By decreasing the amount of our indebtedness and required cash interest payments, we reduced the amount of our cash flow from operations needed to pay interest on our indebtedness so that more of our capital resources could be utilized for drilling activities and paying other expenses. Exploitation and Development Activity During 2003, we continued exploitation activities on our U.S. properties. We participated in the drilling of 24 gross (11.8 net) wells with 23 gross (11.3 net) being successful. The Company invested $18.3 million in capital spending on these activities during 2003. At the end of 2003, as a result of these activities, our average daily production was approximately 24 MMcfepd, a 26% increase from the daily production rate at the beginning of the year (excluding production from the Canadian properties sold in January 2003). Outlook for 2004. As a result of final 2003 financial results and current market conditions, Abraxas has updated its operating and financial guidance for year 2004 as follows: 30 Production: BCFE (approximately 80% gas........................ 8-9 Price Differentials (Pre Hedge): $ Per Bbl.......................................... 0.86 $ Per Mcf.......................................... 0.64 Lifting Coas, $ Per Mce............................... 1.29 G&A, $ Per Mcfe....................................... 0.60 Capital Expenditures ($ Millions)..................... 10.00 Results of Operations 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 (1) 2002 (1) 2003 (1) ------------------- ------------------- ------------------- Operating revenue: Crude oil sales............................. $ 11,184 $ 7,114 $ 7,627 NGLs sales ................................. 5,979 4,343 911 Natural gas sales........................... 56,038 39,405 29,567 Gas processing revenue...................... 2,438 2,420 133 Rig and other............................... 1,604 1,038 781 ------------------- ------------------- ------------------- Total operating revenues ................... $ 77,243 $ 54,320 $ 39,019 =================== =================== =================== Operating income (loss)..................... $ 19,125 $ (110,903) $ 11,542 Crude oil production (MBbls)................ 454.1 292.3 251.6 NGLs production (MBbls)..................... 278.0 242.0 37.3 Natural gas production (MMcf)............... 17,495.6 15,452.7 6,189.4 Average crude oil sales price (per Bbl) $ 24.63 $ 24.34 $ 30.32 Average NGLs sales price (per Bbl) $ 21.51 $ 17.94 $ 24.47 Average natural gas sales price (per Mcf) $ 3.20 $ 2.55 $ 4.78
Revenue and average sales prices are net of hedging activities. (1) Data for 2001, 2002 and the first 23 days of 2003 includes Canadian Abraxas and Old Grey Wolf which were sold in January 2003. Comparison of Year Ended December 31, 2003 to Year Ended December 31, 2002. Operating Revenue. During the year ended December 31, 2003, operating revenue from crude oil, natural gas and natural gas liquids sales decreased by $12.8 million from $50.9 million in 2002 to $38.1 million in 2003. The decrease in revenue was primarily due to decreased production volumes, primarily due to the sale of our Canadian subsidiaries in January 2003, which was partially offset by higher commodity prices realized during the period. Higher commodity prices contributed $16.5 million to crude oil and natural gas revenue while reduced production volumes had a $29.3 million negative impact on revenue. The Canadian properties which were sold in January 2003 contributed $29.3 million to revenues from crude oil and natural gas for the year ended December 31, 2002, compared to $3.1 million in 2003 through the date of sale (January 23, 2003). Natural gas liquids volumes declined from 242.0 MBbls in 2002 to 37.3 MBbls in 2003 The decline in natual gas liquids volumes was due almost entirely to the sale of our Canadian subsidiaries in January 2003. These properties contributed 232.5 MBbls of natural gas liquids in 2002 compared to 11.7 MBbls during 2003. Crude oil sales volumes declined from 292.3 MBbls in 2002 to 251.6 MBbls during 31 2003. The Canadian properties which were sold in January 2003 contributed 27.7 MBbls of crude oil production in 2002 compared to 2.4 MBbls in 2003 through the date of the sale. Crude oil production volumes relating to the Canadian properties which were retained and current drilling activities in Canada resulted in an increase to 29.0 MBbls in 2003 compared to 9.5 MBbls in 2002. Crude oil production from U.S. operations decreased due primarily to natural field declines. Natural gas sales volumes decreased from 15.5 Bcf in 2002 to 6.2 Bcf in 2003. This decrease is primarily due to the sale of our Canadian subsidiaries in January 2003. The Canadian properties sold contributed 9.8 Bcf in 2002 compared to .558 MMcf in 2003 through the date of sale. Average sales prices in 2003 net of hedging costs were: o $30.32 per Bbl of crude oil, o $24.47 per Bbl of natural gas liquids, and o $ 4.78 per Mcf of natural gas. Average sales prices in 2002 net of hedging costs were: o $24.34 per Bbl of crude oil, o $17.94 per Bbl of natural gas liquids, and o $ 2.55 per Mcf of natural gas. Lease Operating Expense. Lease operating expense, or LOE, decreased from $15.2 million in 2002 to $9.6 million in 2003 The decrease in LOE is primarily due the sale of Canadian Abraxas and Old Grey Wolf in January 2003. LOE related to the properties owned by Canadian Abraxas and Old Grey Wolf was $7.3 million for the year ended December 31, 2002. Excluding the properties sold, LOE attributable to on going operations increased, primarily due to higher production taxes associated with higher commodity prices in 2003 as compared to 2002. Our LOE on a per Mcfe basis for the year ended December 31, 2003 was $1.21 per Mcfe compared to $0.82 for 2002, primarily due to the decrease in production volumes. G&A Expense. General and administrative, or G&A, expense decreased from $6.9 million in 2002 to $5.4 million in 2003 The decrease in G&A expense was primarily due to a reduction in personnel in connection with the sale of Canadian Abraxas and Old Grey Wolf on January 23, 2003. Our G&A expense on a per Mcfe basis increased from $0.37 in 2002 to $0.67 in 2003. The increase in the per Mcfe cost was due primarily to lower production volumes in 2003 as compared to 2002. 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. In January 2003, we amended the exercise price to $0.66 per share on certain options with an existing exercise price greater than $0.66 per share which resulted in variable accounting. We charged approximately $1.1 million to stock based compensation expense in 2003 related to these repricings. During 2002, we did not recognize any stock-based compensation due to the decline in the price of our common stock. DD&A Expense. Depreciation, depletion and amortization, or DD&A, expense decreased by $15.7 million from $26.5 million in 2002 to $10.8 million in 2003. The decrease in DD&A was primarily due to the sale of our Canadian subsidiaries in January 2003 as well as ceiling limitation write-downs in the second quarter of 2002. Our DD&A expense on a per Mcfe basis for 2003 was $1.33 per Mcfe as compared to $1.42 per Mcfe in 2002. Interest Expense. Interest expense decreased from $34.1 million to $17.0 million for 2003 compared to 2002. The decrease in interest expense was due to the reduction in debt in 2003. Total debt was reduced as a result of the transactions which occurred on January 23, 2003. Total debt was $300.4 million as of December 31, 2002 compared to $184.6 million at December 31, 2003. 32 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 more information on the full cost method of accounting, you should read the description under "Critical Accounting Policies-- Full Cost Method of Accounting for Crude Oil and Natural Gas Activities". At June 30, 2002, our net capitalized costs of crude oil and natural gas properties exceeded the present value of our estimated proved reserves by $138.7 million ($28.2 million on the U.S. properties and $110.5 million on the Canadian properties). These amounts were calculated considering June 30, 2002 prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. Subsequent to June 30, 2002, commodity prices increased in Canada and we utilized these increased prices in calculating the ceiling limitation write-down. The total write-down was approximately $116.0 million. At December 31, 2003 our net capitalized cost of crude oil and natural gas properties did not exceed the present value of our estimated reserves, due to increased commodity prices during 2003 and, as such, no write-down was recorded in 2003. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. 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. Income taxes. Income tax expense increased from a benefit of $29.7 million for the year ended December 31, 2002 to an expense of $377,000 for the year ended December 31, 2003. The expense in 2003 was related to the operations of the Canadian properties prior to their sale on January 23, 2003. There is no current or deferred income tax expense for 2003 related to on-going operations due to the valuation allowance which has been recorded against the deferred tax asset. Comparison of Year Ended December 31, 2002 to Year Ended December 31, 2001. Operating Revenue. During the year ended December 31, 2002, operating revenue from crude oil, natural gas and natural gas liquids sales decreased by $22.3 million from $73.2 million in 2001 to $50.9 million in 2002. This decrease was primarily attributable to a decrease in production volumes and lower commodity prices in 2002 as compared to 2001. Crude oil and natural gas revenue was impacted by $11.5 million from a decline in commodity prices and $10.8 million from reduced production. The decline in production was due to the disposition of certain properties in south Texas and natural field declines. Natural gas liquids volumes declined from 278.0 MBbls in 2001 to 242.0 MBbls in 2002. Crude oil sales volumes declined from 454.1 MBbls in 2001 to 292.3 MBbls during 2002. Natural gas sales volumes decreased from 17.5 Bcf in 2001 to 15.5 Bcf in 2002. Production declines were primarily attributable to our disposition of assets during 2002 and natural field declines. Average sales prices in 2002 net of hedging losses were: o $ 24.34 per Bbl of crude oil, o $ 17.94 per Bbl of natural gas liquids, and o $ 2.55 per Mcf of natural gas. 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. 33 Lease Operating Expense. LOE expense decreased from $18.6 million in 2001 to $15.2 million in 2002. LOE on a per Mcfe basis for 2002 was $0.82 per Mcfe as compared to $0.83 per Mcfe in 2001. The decrease in the per Mcfe cost is due to a reduced operating cost offset by the decline in production volumes. G&A Expense. G&A expense increased slightly from $6.4 million in 2001 to $6.9 million in 2002. This increase was due primarily to increased legal expenses related to ongoing litigation in 2002. Our G&A expense on a per Mcfe basis increased from $0.30 in 2001 to $0.37 in 2002. The increase in the per Mcfe cost was due primarily to lower production volumes in 2002 as compared to 2001. 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. During 2002, we did not recognize any stock-based compensation due to the decline in the price of our common stock. DD&A Expense. DD&A expense decreased by $5.9 million from $32.4 million in 2001 to $26.5 million in 2002. The decline in DD&A is due to reductions in our full cost pool resulting from ceiling test write-downs, as well as lower production volumes. Our DD&A expense on a per Mcfe basis for 2002 was $1.42 per Mcfe as compared to $1.74 per Mcfe in 2001. Interest Expense. Interest expense increased from $31.5 million to $34.1 million for 2002 compared to 2001. The increase was the result of additional sales pursuant to our production payment arrangement with Mirant Americas as well as increased borrowings under Old Grey Wolf's credit facility in 2002. The production payment was reacquired in June 2002 for approximately $6.8 million. 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 more information on the full cost method of accounting, you should read the description under "Critical Accounting Policies-- Full Cost Method of Accounting for Crude Oil and Natural Gas Activities". 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. 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. At June 30, 2002, our net capitalized costs of crude oil and natural gas properties exceeded the present value of our estimated proved reserves by $138.7 million ($28.2 million on the U.S. properties and $110.5 million on the Canadian properties). These amounts were calculated considering June 30, 2002 prices of $26.12 per Bbl for crude oil and $2.16 per Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. Subsequent to June 30, 2002, commodity prices increased in Canada and we utilized these increased prices in calculating the ceiling limitation write-down. The total write-down was approximately $116.0 million. At December 31, 2002, our net capitalized cost of crude oil and natural gas properties did not exceed the present value of our estimated reserves, due to increased commodity prices during the fourth quarter and, as such, no further write-down was recorded. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. 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 34 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. Income taxes. Income tax expense decreased from an expense of $2.4 million for the year ended December 31, 2001 to a benefit of $29.7 million for the year ended December 31, 2002. The decrease was primarily due to the tax benefit relating to the ceiling limitation write-down related to our Canadian properties. Liquidity and Capital Resources General. The crude oil and natural gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following costs: o the development of existing properties, including drilling and completion costs of wells; o acquisition of interests in crude oil and natural gas properties; and o production and transportation facilities. The amount of capital available to us will affect our ability to service our existing debt obligations and to continue to grow the business through the development of existing properties and the acquisition of new properties. Our sources of capital are primarily cash on hand, cash from operating activities, funding under the senior credit agreement and the sale of properties. Our overall liquidity depends heavily on the prevailing prices of crude oil and natural gas and our production volumes of crude oil and natural gas. Significant downturns in commodity prices, such as that experienced in the last nine months of 2001 and the first quarter of 2002, can reduce our cash from operating activities. Although we have hedged a portion of our natural gas and crude oil production and will continue this practice as required pursuant to the senior credit agreement, future crude oil and natural gas price declines would have a material adverse effect on our overall results, and therefore, our liquidity. Low crude oil and natural gas prices could also negatively affect our ability to raise capital on terms favorable to us and could also reduce the borrowing base under our senior credit agreement. If the volume of crude oil and natural gas we produce decreases, our cash flow from operations will decrease. Our production volumes will decline as reserves are produced. In addition, due to sales of properties in 2002 and January 2003, we now have reduced reserves and production levels. In the future, we may sell additional properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration, exploitation and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. While we have had some success in pursuing these activities, historically, we have not been able to fully replace the production volumes lost from natural field declines and property sales. Working Capital. At December 31, 2003, our current liabilities of approximately $12.6 million exceeded our current assets of $10.2 million resulting in a working capital deficit of $2.4 million. This compares to a working capital deficit of $65.7 million as of December 31, 2002. Current liabilities as of December 31, 2003 consisted of trade payables of $6.8 million, revenues due third parties $2.3 million, accrued interest related to our New Notes of $2.3 million, of which $2.0 is non-cash and other accrued liabilities of $ 1.2 million. We do not expect to make cash interest payments with respect to the outstanding New Notes, and the issuance of additional New Notes in lieu of cash interest payments thereon will not affect our working capital balance. 35 Capital Expenditures. Capital expenditures in 2001, 2002 and 2003 were $57.1 million, $38.7 million and $18.3 million, respectively. The table below sets forth the components of these capital expenditures for the three years ended December 31, 2003. Year Ended December 31, ----------------------------------------- 2001 2002 2003 ---- ---- ---- (dollars in thousands) Expenditure category: Development $ 56,694 $ 38,560 $ 18,313 Facilities and other 362 154 36 ------------- ------------ ------------ Total $ 57,056 $ 38,714 $ 18,349 ============= ============= ============ ------------------ During 2001, 2002 and 2003, capital expenditures were primarily for the development of existing properties. We currently have a capital expenditure budget of $10 million for 2004, of which $5.0 million is allocated to U.S. projects and $5.0 million is allocated to Canadian drilling projects. We plan to participate in the drilling or putting on production of 17 gross (13 net) wells, of which 11 gross (11 net) wells will be operated by us. Our capital expenditures could also include expenditures 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 from current levels, our cash flows will decrease which may result in a reduction of the capital expenditures budget. If we decrease our capital expenditures budget, we may not be able to offset crude oil and natural gas production volumes decreases caused by natural field declines and sales of producing properties. Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below:
2001 2002 2003 ---- ---- ---- (dollars in thousands) Net cash (used in) provided by operating activities $ 16,263 $ (8,336) $ 23,850 Net cash (used in) provided by investing activities (30,797) (5,036) 67,461 Net cash provided by (used in) financing activities 20,685 10,836 (95,622) -------------- ------------- ------------ Total $ 6,151 $ (2,536) $ (4,311) ============== ============= ============
Operating activities for the year ended December 31, 2003 provided us with $23.9 million of cash. Investing activities provided us $67.5 million during 2003. Financing activities used $95.6 million during 2003. Most of these funds were used to reduce our long-term debt and were generated by the sale of our Canadian subsidiaries and the exchange offer completed in January 2003. The sale of our Canadian subsidiaries contributed $85.8 million in 2003 reduced by $18.3 million in exploration and development expenditures. Expenditures in 2003 were primarily for the development of crude oil and natural gas properties. Operating activities for the year ended December 31, 2002 used $8.4 million of cash. Investing activities used $5.0 million during 2002. Our investing activities included the sale of properties which provided $33.9 million, and the use of $38.9 million primarily for the development of producing properties. Financing activities provided us with $10.8 million during 2002, relating primarily to advances on Old Grey Wolf's credit facility. Operating activities for the year ended December 31, 2001 provided us $16.3 million of cash. Investing activities included the sale of properties which 36 provided $28.9 million, and the use of $57.1 million for the development of producing properties and $2.7 million for the acquisition of the minority interest in Grey Wolf. 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 Old Grey Wolf's credit facility. Payments on long-term debt used $9.3 million. Future Capital Resources. We will have four principal sources of liquidity going forward: (i) cash on hand, (ii) cash from operating activities, (iii) funding under the senior credit agreement, and (iv) sales of producing properties. Covenants under the indenture for the New Notes and the senior credit agreement restrict our use of cash on hand, cash from operating activities and any proceeds from asset sales. We may also attempt to raise additional capital through the issuance of additional debt or equity securities, although the terms of the new note indenture and the senior credit agreement substantially restrict 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. Contractual Obligations We are committed to making cash payments in the future on the following types of agreements: o Long-term debt o Operating leases for office facilities We have no off-balance sheet debt or unrecorded obligations and we have not guaranteed the debt of any other party. Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2003.
Contractual Obligations Payments due in: (dollars in thousands) --------------------------- -------------------------------------------------------------------------- Total Less than More than 5 one year 1-3 years 3-5 years years ----------------------------- -------------- ------------- ------------- -------------- -------------- Long-Term Debt (1) $ 241,399 $ - $ 57,155 $ 184,244 $ - Operating Leases (2) 1,373 416 796 161 -
(1) These amounts represent the balances outstanding under the senior credit agreement and the New Notes. These repayments assume that interest will be capitalized under the New Notes and that periodic interest on the senior credit agreement will be paid on a monthly basis and that we will not draw down additional funds thereunder. (2) These amounts represent office lease obligations. Leases for office space for Abraxas and New Grey Wolf expire in April 2006 and December 2008, respectively. 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, 37 sales of properties, sales of production payments 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. Long-Term Indebtedness. The financial restructuring completed in January 2003 resulted in the retirement of our first lien notes, second lien notes and old notes, together with the Old Grey Wolf credit facility. The following table sets forth our long-term indebtedness as of December 31, 2002, and 2003.
Long Term Indebtedness December 31 -------------------------------- 2002 2003 ----------------- -------------- (in thousands) 11.5% Senior Notes due 2004 ("Old Notes") ......................... $ 801 $ - 12.875% Senior Secured Notes due 2003 ("First Lien Notes") ........ 63,500 - 11.5% Second Lien Notes due 2004 ("Second Lien Notes")............. 190,178 - 9.5% Senior Credit Facility ("Grey Wolf Facility") providing for borrowings up to approximately US $96 million (CDN $150 million). Secured by the assets of Old Grey Wolf and non-recourse to Abraxas....................................... 45,964 - 11.5% Secured Notes due 2007 ("New Notes")......................... - 137,258 Senior Credit Agreement ........................................... - 47,391 (1) ----------------- --------------- 300,443 184,649 Less current maturities ........................................... 63,500 - ----------------- --------------- $ 236,943 $ 184,649 ================= =============== ----------------
(1) At March 2, 2004, the outstanding principal balance on our senior credit agreement was $50.7 million. For financial reporting purposes, the New Notes are reflected at the carrying value of the Second Lien Notes and Old Notes prior to the exchange of $191.0 million, net of the cash offered in the exchange of $47.5 million and net of the fair market value related to equity of $3.8 million offered in the exchange transaction. The face amount of the New Notes was $120.5 million at December 31, 2003 including $10.8 million in new notes issued for interest. The New Notes accrue interest from the date of issuance, at a fixed annual rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1, commencing May 1, 2003. We will pay such unpaid interest in kind by the issuance of additional New Notes with a principal amount equal to the amount of accrued and unpaid cash interest on the New Notes plus an additional 1% accrued interest for the applicable period. Upon an event of default, the New Notes accrue interest at an annual rate of 16.5%. The New Notes are secured by a second lien or charge on all of our current and future assets, including, but not limited to, all of our crude oil and natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas, Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes. If Abraxas cannot make payments on the New Notes when they are due, the guarantors must make them instead. The New Notes and related guarantees o are subordinated to the indebtedness under the new senior secured credit agreement; o rank equally with all of Abraxas' current and future senior indebtedness; and o rank senior to all of Abraxas' current and future subordinated indebtedness, in each case, if any. 38 The New Notes are subordinated to amounts outstanding under the new senior secured credit agreement both in right of payment and with respect to lien priority and are subject to an intercreditor agreement. Abraxas may redeem the New Notes, at its option, in whole at any time or in part from time to time, at redemption prices expressed as percentages of the principal amount set forth below. If Abraxas redeems all or any New Notes, it must also pay all interest accrued and unpaid to the applicable redemption date. The redemption prices for the New Notes during the indicated time periods are as follows: Period Percentage From January 24, 2004 to June 23, 2004............................97.1674% From June 24, 2004 to January 23, 2005............................98.5837% Thereafter.......................................................100.0000% Under the indenture, we are subject to customary covenants which, among other things, restrict our ability to: o borrow money or issue preferred stock; o pay dividends on stock or purchase stock; o make other asset transfers; o transact business with affiliates; o sell stock of subsidiaries; o engage in any new line of business; o impair the security interest in any collateral for the notes; o use assets as security in other transactions; and o sell certain assets or merge with or into other companies. In addition, we are subject to certain financial covenants including covenants limiting our selling, general and administrative expenses and capital expenditures, a covenant requiring Abraxas to maintain a specified ratio of consolidated EBITDA, as defined in the agreements, to cash interest and a covenant requiring Abraxas to permanently, to the extent permitted, pay down debt under the new senior secured credit agreement and, to the extent permitted by the new senior secured credit agreement, the New Notes or, if not permitted, paying indebtedness under the new senior secured credit agreement. The indenture 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 our financial condition. Senior Credit Agreement. In connection with the financial restructuring, Abraxas entered into a new senior credit agreement providing a term loan facility and a revolving credit facility as described below. Subsequently, on February 23, 2004, Abraxas entered into an amendment to its existing senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility as described below. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date for these credit facilities is February 1, 2007. In the event of an early termination, we will be required to pay a prepayment premium, except in the limited circumstances described in the amended senior credit agreement. First Revolving Credit Facility. Lenders under the amended senior credit agreement have provided a revolving credit facility to Abraxas with a maximum borrowing base of up to $20 million. Our current borrowing base under this revolving credit facility is the full $20.0 million, subject to adjustments based on periodic calculations and mandatory prepayments under the senior credit agreement. We have borrowed $6.6 million under this revolving credit facility, 39 which was used to refinance principal and interest on advances under our preexisting revolving credit facility under the senior credit agreement, and to pay certain fees and expenses relating to the transaction. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 1.125%. Second Revolving Credit Facility. Lenders under the amended senior credit agreement have provided a second revolving credit facility to Abraxas, with a maximum borrowing of up to $30 million. This revolving credit facility is not subject to a borrowing base. We have borrowed $30.0 million under this revolving credit facility, which was used to refinance principal and interest on advances under our preexisting revolving credit facility, and to pay certain transaction fees and expenses. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%. Non-Revolving Credit Facility. Abraxas has borrowed $15.0 million pursuant to a non-revolving credit facility, which was used to repay the preexisting term loan under our senior credit agreement, to refinance principal and interest on advances under the preexisting revolving credit facility, and to pay certain transaction fees and expenses. This non-revolving credit facility is not subject to a borrowing base. Outstanding amounts under this credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%. Covenants. Under the amended senior credit agreement, Abraxas is subject to customary covenants and reporting requirements. Certain financial covenants require Abraxas to maintain minimum ratios of consolidated EBITDA (as defined in the amended senior credit agreement) to adjusted fixed charges (which includes certain capital expenditures), minimum ratios of consolidated EBITDA to cash interest expense, a minimum level of unrestricted cash and revolving credit availability, minimum hydrocarbon production volumes and minimum proved developed hydrocarbon reserves. In addition, if on the day before the end of each fiscal quarter the aggregate amount of our cash and cash equivalents exceeds $2.0 million, we are required to repay the loans under the amended senior credit agreement in an amount equal to such excess. The amended senior credit agreement also requires us to enter into hedging agreements on not less than 40% or more than 75% of our projected oil and gas production. We are also required to establish deposit accounts at financial institutions acceptable to the lenders and we are required to direct our customers to make all payments into these accounts. The amounts in these accounts will be transferred to the lenders upon the occurrence and during the continuance of an event of default under the amended senior credit agreement. In addition to the foregoing and other customary covenants, the amended senior credit agreement contains a number of covenants that, among other things, restrict our ability to: o incur additional indebtedness; o create or permit to be created liens on any of our properties; o enter into change of control transactions; o dispose of our assets; o change our name or the nature of our business; o make guarantees with respect to the obligations of third parties; o enter into forward sales contracts; o make payments in connection with distributions, dividends or redemptions relating to our outstanding securities, or o make investments or incur liabilities. 40 Security. The obligations of Abraxas under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of Abraxas' assets, including all crude oil and natural gas properties. Guarantees. The obligations of Abraxas under the amended senior credit agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas, Sandia Operating, Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of the guarantors' assets, including all crude oil and natural gas properties. Events of Default. The amended senior credit agreement 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 our financial condition. 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. Under the senior credit agreement, we are required to maintain hedge positions on not less than 40% or more than 75% of our projected oil and gas production for a six month rolling period. See "Item 7A--Quantitative and Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further information. Net Operating Loss Carryforwards At December 31, 2003, the Company had, subject to the limitation discussed below, $100.6 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2022 if not utilized. In connection with January 2003 transactions described in Note 2, in Notes to Consolidated Financial Statements, Item 8, certain of the loss carryforwards were utilized. 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 $99.1 million and $76.1 million for deferred tax assets at December 31, 2002 and 2003, respectively. Related Party Transactions Accounts receivable - Other includes approximately $51,211 and $35,558 as of December 31, 2002 and 2003, respectively, representing amounts due from officers relating to advances made to employees. On July 29, 2003 Abraxas acquired all of the shares of the capital stock of Wind River Resources Corporation which owned an airplane. The sole shareholder of Wind River was the Company's President. The consideration for the purchase was 106,977 shares of Abraxas common stock and $35,000 in cash. Simultaneously with this transaction, the airplane was sold. The airplane had previously been made available to Abraxas employees for business use. The Company paid Wind River a total of approximately $314,000, $345,000 and $132,000 in 2001, 2002 and 2003, through July 29, 2003 respectively, for Wind River's operating cost associated with the Company's use of the plane. 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. 41 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 under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our crude oil and natural gas properties. At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. 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, most recently in 2002. 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 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 operating activities, but does reduce our stockholders' equity and reported 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 depressed or volatile. 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. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. For the year ended December 31, 2002, we recorded a write-down of approximately $116.0 million. The write-down in 2002 was due to low commodity prices. We cannot assure you that we will not experience additional write-downs in the future. Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of: o the quality and quantity of available data; o the interpretation of that data; o the accuracy of various mandated economic assumptions; o and the judgment of the persons preparing the estimate. 42 The Company's proved reserve information included in this Report was based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which the Company records DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. Use of Estimates. The preparation of consolidated 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 consolidated 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. 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. The Company had no material gas imbalances. Asset Retirement Obligations The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense. Hedge Accounting. From time to time, we use commodity price hedges to limit our exposure to fluctuations in crude oil and natural gas prices. Results of those hedging transactions are reflected in crude oil and natural gas sales. 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. Under this statement, all derivatives, whether designated in hedging relationships or not, are required to be recorded at fair value on our balance sheet. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results of the hedged item in the consolidated statement of operations. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. For derivative instruments 43 designated as fair value hedges, changes in fair value, to the extent the hedge is effective, are recognized as an increase or decrease to the value of the hedged item until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. Changes in fair value of contracts that do not meet the SFAS 133 definition of a cash flow or fair value hedge are also recognized in earnings through risk management income. All amounts initially recorded in this caption are ultimately reversed within the same caption and included in oil and gas sales or interest expense, as applicable, over the respective contract terms. One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control. Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated because energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control. Due to the volatility of crude oil and natural gas prices and, to a lesser extent, interest rates, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2003 the net market value of our derivatives was an asset of $21,136. As of December 31, 2002 we did not have any outstanding derivatives. New Accounting Pronouncements A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $3.1 million and $4.2 million at December 31, 2002 and December 31, 2003, respectively, out of oil and gas properties and into a separate intangible assets line item. The Company's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full-cost accounting rules. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 is effective for us January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. 44 The Company adopted SFAS 143 effective January 1, 2003. For the year ended December 31, 2003 the Company recorded a charge of $395,341 for the cumulative effect of the change in accounting principal and a liability of $1.3 million. During 2003, the Company charged approximately $379,000 to expense related to the accretion of the liability. The impact on each of the prior periods was not material. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1, 2002, the Company adopted SFAS 144. SFAS 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 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. This new standard had no impact on the Company's consolidated financial statements for the year ended December 31, 2003. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs associated with exit of disposal activities to be recognized when they are incurred rather than at the date of commitment to an exit or disposal plan. The Company is currently evaluating the impact the standard will have on its results of operations and financial condition. The official effective date of this standard has not been determined by the FASB. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 149, among other things, clarifies the circumstances under which a contract with an initial net investment meets the characteristic of a derivative and amends the definition of an "underlying" to conform it to language used in FIN 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. The Company adopted this statement effective July 1, 2003. Implementation of this new standard did not have an effect on the Company's consolidated financial position or results of operations. In November 2002 the FASB issued FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees that it has issued, including loan guarantees such as standby letters of credit. It also requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken in issuing the guarantee. The Interpretation does not specify the subsequent measurement of the guarantor's recognized liability over the term of the related guarantee. The guidance in FIN 45 does not apply to certain guarantee contracts, such as those issued by insurance companies or for a lessee's residual value guarantee embedded in a capital lease. The provisions related to recognizing a liability at inception of the guarantee for the fair value of the guarantor's obligations would not apply to product warranties or to guarantees accounted for as derivatives. The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002, regardless of the guarantor's fiscal year-end. FIN 45 specifies additional disclosures effective for financial statements of interim or annual periods ending after December 15, 2002. In January 2003 the FASB issued FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable-Interest Entities (VIEs".) FIN 46 establishes the definition of VIEs to encompass a broader group of entities than those previously considered special-purpose entities (SPEs). FIN 46 specifies the criteria under which it is appropriate for an investor to consolidate VIEs; in order for an investor to consolidate a VIE, the entity must fall within the definition of VIE and the investor must fall within the definition of primary beneficiary, both newly defined terms under this FIN. The revised effective date of FIN 46 for public companies with VIEs meeting certain conditions, will be the end of the first interim or annual period ending after December 15, 2003. In December 2003, the FASB issued FASB Interpretaion no. 46(R)m which expanded and clarified the guidelines of FIN 46. 45 In May 2003, the FASB issued FAS No. 150, entitled "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity"(SFAS 150). This statement is effective for financial instruments entered into or modified after May 31, 2003, and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company has no financial instruments affected by SFAS 150, therefore adoption by the Company as of July 1, 2003 will not impact the Company's financial statements. 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. 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. Assuming the production levels we attained during the year ended December 31, 2003, 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 $3.8 million for the year. Hedging Sensitivity On January 1, 2001, we adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge or cash flow hedge. If the derivative qualifies for cash flow 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. As of December 31, 2003 the derivatives that we have in place are not designated as hedges. Accordingly, changes in the fair market value of the derivatives are recorded in current period oil and gas revenue. If a derivative qualifies for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in accumulated Other Comprehensive Income/Loss related to a cash flow hedge that becomes ineffective, remain unchanged until the related production is delivered. If we determine that it is probable that a hedged transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. Gains and losses on qualified hedging instruments related to accumulated Other Comprehensive Income and adjustments to carrying amounts on hedged production are included in natural gas or crude oil production revenue in the period that the related production is delivered. For derivatives not qualifying for hedge accounting, changes in the fair market value of the instrument are charged to income in the current period. In 2001 and 2002, we experienced hedging losses of $12.1 million and $3.2 million, respectively. In October 2002, all of these hedge agreements expired. Under the expired hedge agreements, we made total payments to various counterparties in the amount of $35.1 million. 46 Under the terms of the senior secured credit agreement, we are required to maintain hedging positions with respect to not less than 40% nor more than 75% of our crude oil and natural gas production for a rolling six month period. As of December 31, 2003 the Company's hedge positions were as follows: Time Period Notional Quantities Price --------------------------------- ------------------------------ --------------- March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50 2004 production per day March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00 production per day March 1, 2004 - April 30, 2004 500 Bbls of crude oil Floor of $22.00 production per day May 2004 2,000 Mmbtu of natural gas Floor of $4.00 production per day May 2004 500 Bbls of crude oil Floor of $22.00 production per day June 2004 800 Bbls of crude oil Floor of $22.00 production per day July 2004 2,000 Mmbtu of natural gas Floor of $4.00 production per day July 2004 500 Bbls of crude oil Floor of $22.00 production per day Subsequent to year-end we have entered into additional agreements similar to those scheduled above (floors) in volume amounts sufficient to reach the 40% threshold required by our senior credit agreement. The Company anticipates continuing to purchase similar floors in the future to satisfy our requirements under the senior credit agreement. Interest rate risk At December 31, 2003, as a result of the financial restructuring that occurred in January 2003, we had approximately $47.4 million in outstanding indebtedness under the new senior secured credit agreement, accruing interest at a rate of prime plus 4.5%, subject to a minimum interest rate of 9.0%. In the event that the prime rate (currently 4.0%) rises above 4.5% the interest rate applicable to our outstanding indebtedness under the new senior secured credit agreement will rise accordingly. For every percentage point that the prime rate rises above 4.5%, our interest expense would increase by approximately $430,000 on an annual basis. Our New Notes accrue interest at fixed rates and are accordingly not subject to fluctuations in market rates. As discussed in "Business - General" the senior secured credit agreement was amended in February 2004. Our interest rate under the terms of the amended credit agreement is a floating rate, currently at approximately 7.5%, assuming all available amounts are borrowed. 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. Our ongoing Canadian operations reported a pre-tax income $218,000 for the year ended December 31, 2003. 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 $10,900. 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. 47 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure As noted in the form 8-K filed on April 23, 2003, the Board of Directors of Abraxas Petroleum Corporation engaged the accounting firm of BDO Seidman, LLP as the Company's certifying accountant for the year ended December 31, 2003. The engagement of BDO Seidman, LLP was approved by the Audit Committee of the Board of Directors. The Audit Committee of the Board of Directors approved the dismissal of Deloitte & Touche LLP. The reports of Deloitte & Touche LLP on the Company's financial statements for the two fiscal years ended December 31, 2001 and 2002 did not contain any adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles. In connection with the audits of the Company's financial statements for each of the two fiscal years ended December 31, 2001 and 2002, there were no disagreements with Deloitte & Touche LLP on any matters of accounting principles, financial statement disclosure or audit scope and procedures which, if not resolved to the satisfaction of Deloitte & Touche LLP, would have caused the firm to make reference to the matter in their report. Item 9A. Controls and Procedures As of the end of the period covered by this report, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of Abraxas' "disclosure controls and procedures" (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e)and 15d-15(e)) and concluded that the disclosure controls and procedures were adequate and designed to ensure that material information relating to Abraxas and our consolidated subsidiaries which is required to be included in our periodic Securities and Exchange Commission filings would be made known to them by others within those entities. There were no changes in our internal controls that could materially affect, or are reasonably likely to materially affect our financial reporting. 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 2004 Annual Meeting of Stockholders which appears therein under the captions "Election of Directors". See also the information in Item 4a of Part I of this Report. Audit Committee and Audit Committee Financial Expert The Audit Committee of Abraxas' board of directors consists of C. Scott Bartlett, Jr., Frank M. Burke, James C. Phelps and Joseph A. Wagda. The board of directors has determined that each of the members of the Audit Committee is independent as determined in accordance with the listing standards of the American Stock Exchange and Item 7(d) (3) (iv) of Schedule 14A of the Exchange Act. In addition, the board of directors has determined that C. Scott Bartlett, Jr., as defined by SEC rules, is an audit committee financial expert. Section 16(a) Compliance Section 16(a) of the Exchange Act requires Abraxas directors and executive officers and persons who own more than 10% of a registered class of Abraxas equity securities to file with the Securities and Exchange Commission and the AMEX initial reports of ownership and reports of changes in ownership of Abraxas common stock. Officers, directors and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all such forms they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, Abraxas believes that all its directors and executive officers during 2003 complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act. 48 Item 11. Executive Compensation There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2004 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 2004 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 2004 Annual Meeting of Stockholders which appears therein under the caption "Certain Transactions." Item 14. Principal Accountant Fees and Services There is incorporated in this Item 14 by reference that portion of our definitive proxy statement for the 2004 Annual Meeting of Stockholders which appears therein under the caption "Principal Auditor Fees and Services." PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a)1. Consolidated Financial Statements Page Report of BDO Seidman LLP Independent Auditors....................F-2 Report of Deloitte & Touche LLP, Independent Auditors..............F-3 Consolidated Balance Sheets, December 31, 2002 and 2003.......................................F-4 Consolidated Statements of Operations, Years Ended December 31, 2001, 2002 and 2003.....................F-6 Consolidated Statements of Stockholders' Deficit Years Ended December 31, 2001, 2002 and 2003 ...................F-7 Consolidated Statements of Cash Flows Years Ended December 31, 2001, 2002 and 2003.....................F-9 Consolidated Statements of Other Comprehensive Income (loss) Years Ended December 31, 2001, 2002 and 2003....................F-11 Notes to Consolidated Financial Statements........................F-12 Grey Wolf Exploration Inc. Auditors' Reports for the years ended December 31, 2001 and 2002..F-45 49 Comments by Auditors' for US readers on Canada - US reporting differences...........................................F-46 Balance Sheet at December 31, 2002................................F-47 Statements of Earnings and Retained Earnings for the years ended December 31, 2002 and 2001 .....................................F-48 Statements of Cash Flows for the years ended December 31, 2002 and 2001.....................................F-49 Notes to Financial Statements.....................................F-51 (a)2. Financial Statement Schedules 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 as Exhibit 3.6 to Abraxas' Annual Report on Form 10-K filed April 5, 2002). 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). 50 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 23, 2003, by and among Abraxas, as Issuer; the subsidiary Guarantors party thereto and U.S. Bank, N.A., as Trustee, relating to Abraxas' 11-1/2 % Secured Notes Due 2007. (filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K dated February 6, 2003). 4.7 Form of 111/2% Secured Notes due 2007. (Filed as Exhibit A to Exhibit 4.6). *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'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). 10.10 Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.30 to the 1993 S-1). 10.15 Common Stock Purchase Warrant dated September 1, 2000 between 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 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). 51 10.20 Farmout Agreement between Grey Wolf Exploration Limited and PrimeWest Energy, Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K/A filed on December 9, 2002). 10.21 Amendment No. 2 dated as of February 23, 2004 to Loan and Security Agreement by and among Abraxas Petroleum Corporation, the subsidiaries of Abraxas that are signatories thereto, as Guarantors, the Lenders that are signatories thereto, as Lenders, and Wells Fargo Foothill, Inc., formerly known as Foothill Capital Corporation, as the Arranger and Administrative Agent (Filed as Exhibit 10.1 to Abraxas Current Report on Form 8-K filed on February 26, 2004). 10.22 Intercreditor and Subordination Agreement dated as of January 23, 2003, by and among Foothill, in its capacity as agent (in such capacity, together with any successor in such capacity, the "Senior Agent") for the lenders who are from time to time parties to the Loan Agreement (the "Senior Lenders"), U.S. Bank, N.A., a national banking association in its capacity as trustee (in such capacity, together with any successor in such capacity, the "Trustee") for the holders of the 11 1/2% Secured Notes Due 2007, issued under the Indenture. (Filed as Exhibit 10.6 to Abraxas' Current Report on Form 8-K filed February 6, 2003). 16.1 Letter addressing change in certifying accountant (Filed on Abraxas' Form 8-K filed on August 22, 2001). 21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas, Grey Wolf Exploration Inc., Sandia Oil & Gas Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc., Western Associated Energy Corporation and Eastside Coal Company, Inc.'s Registration Statement on Form S-1, No. 333-103027). 23.1 Consent of BDO Seidman, LLP (filed herewith) 23.2 Consent of Deloitte & Touche LLP (filed herewith). 23.3 Consent of Deloitte & Touche LLP Chartered Accountants (filed herewith). 23.4 Consent of DeGolyer and MacNaughton. (filed herewith). 23.5 Consent of McDaniel & Associates Consultants, Ltd. (filed herewith). 31.1 Certification - Chief Executive Officer (filed herewith) 31.2 Certification - Chief Financial Officer (filed herewith) 32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). 32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). * Management Compensatory Plan or Agreement. (b) Reports on Form 8-K 1. Current Report on Form 8-K filed on November 13, 2003, Disclosure of Operations and Financial Condition, including press release announcing Third Quarter 2003 Financial Results. 2. Current Report on Form 8-K filed on February 2, 2004, Regulation FD, including press release announcing Operations Update and Exhibit of materials presented to investors. 52 3. Current Report on Form 8-K filed on February 24, 2004, Regulation FD, including press release announcing amendment to First Lien Credit Facility. 4. Current Report on Form 8-K filed on February 26, 2004, Financial Statements and Exhibits and Regulation FD disclosure, including Amendment No. 2 to Loan and Security Agreement and press release regarding such amendment. 5. Current Report on Form 8-K filed on March 9, 2004, Financial Statements and Exhibits, including press release announcing Forth Quarter 2003 and Year End 2003 Financial Results. 53 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: March 11, 2004 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 Robert L.G. Watson Executive Officer)and Director March 11, 2004 /s/ Chris E. Williford Exec. Vice President and ----------------------- Treasurer (Principal Financial Chris Williford and Accounting Officer) March 11, 2004 /s/ Craig S. Bartlett, Jr. Director March 11, 2004 -------------------------- Craig S. Bartlett, Jr. /s/ Franklin Burke Director March 11, 2004 ------------------ Franklin Burke /s/ Harold D. Carter Director March 11, 2004 -------------------- Harold D. Carter /s/ Ralph F. Cox Director March 11, 2004 ----------------- Ralph F. Cox /s/ Barry J. Galt Director March 11, 2004 ------------------ Barry J. Galt /s/ Dennis E. Logue Director March 11, 2004 ------------------- Dennis E Logue /s/ James C. Phelps Director March 11, 2004 ------------------- James C. Phelps /s/ Joseph A. Wagda Director March 11, 2004 ------------------- Joseph A. Wagda 54 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 february 13, 2004, relating to the consolidated financial statements, which appears in the Annual Report to Shareholders, which is incorporated in this Annual Report pmn Fornm 10-K. BDO Seidman, LLP March 9, 2003 55 Exhibit 23.2 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 10, 2003, July 18, 2003, as to Note 19, and the first paragraph of "New Accounting Pronouncements" in Note 1, (which expresses an unqualified opinion and includes two explanatory paragraphs referring to the subsequent events described in Note 2 and the restatement described in Note 19), appearing in this Annual Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December 31, 2003. /s/ Deloitte & Touche LLP San Antonio, Texas March 9, 2004 56 Exhibit 23.3 Independent Auditors' Consent We consent to the incorporation by reference in the Registration Statements No. 33-48932, 33-48934, 33-72268, 33-81416, 33-81418, 333-17375, and 333-17377 of Abraxas Petroleum Corporation on Form S-8 of our report dated March 10, 2003 on the financial statements of Grey Wolf Exploration Inc. (which report expresses an unqualified opinion, and for U.S. readers has a Canada-U.S. reporting difference which would require an explanatory paragraph relating to the Company's changes in accounting policies and significant subsequent events that have been disclosed in the financial statements), appearing in this Annual Report on Form 10-K of Abraxas Petroleum Corporation for the year ended December 31, 2003. Calgary, Canada /s/ Deloitte & Touche LLP March 9, 2004 Chartered Accountants 57 Exhibit 23.3 Consent of DeGolyer and MacNaughton We hereby consent to the incorporation in the "Reserves Information" section of your Annual Report on Form 10-K of the references to DeGolyer and MacNaughton and to the use by reference of information contained in our "Appraisal Report as of December 31, 2003 on Certain Properties owned by Abraxas Petroleum Corporation," "Appraisal Report as of December 31, 2003 on Certain Properties owned by Grey Wolf Exploration Inc. in Canada," "Appraisal Report as of December 31, 2002 on Certain Properties owned by Abraxas Petroleum Corporation," "Appraisal Report as of December 31, 2002 on Certain Properties owned by Grey Wolf Exploration Inc. in Canada," and "Appraisal Report as of December 31, 2001 on Certain Properties owned by Abraxas Petroleum Corporation" (our Reports). However, since the crude oil, condensate, natural gas liquids, and natural gas reserves estimates set forth in our Reports have been combined with reserves estimates of other petroleum consultants or those estimated by Abraxas, we are necessarily unable to verify the accuracy of the reserves estimates contained in the aforementioned Annual Report. DeGolyer and MacNaughton Dallas, Texas March 9, 2004 58 Exhibit 23.4 Consent of McDaniel and Associates Consultants LTD. We consent to the incorporation in your Annual Report on Form 10-K/A 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 April 3, 2002. McDaniel & Associates Consultants LTD Calgary, Alberta April 3, 2002 59 Exhibit 31.1 CERTIFICATIONS I, Robert L. G. Watson, certify that: 1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures, and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting. 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 11, 2004 /s/ Robert L.G. Watson Robert L.G. Watson Chairman of the Board, President and Principal Executive Officer 60 Exhibit 31.2 CERTIFICATIONS I, Chris Williford, certify that: 1. I have reviewed this annual report on Form 10-K of Abraxas Petroleum Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures, and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting. 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 11, 2004 /s/ Chris Williford Chris Williford Executive Vice President and Principal Accounting Officer 61 Exhibit 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Abraxas Petroleum Corporation (the "Company") on Form 10-K for the year ended December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Robert L.G. Watson, Chairman of the Board, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Act of 1934; and (2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Robert L.G. Watson Robert L.G. Watson Chairman of the Board, President and Chief Executive Officer March 11, 2004 This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of ss.18 of the Securities Exchange Act of 1964, as amended. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 62 Exhibit 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Abraxas Petroleum Corporation (the "Company") on Form 10-K for the year ended December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Chris E, Williford, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Act of 1934; and (2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Chris E. Williford Chris E. Williford Executive Vice President and Chief Financial Officer March 11, 2004 This certification accompanies the Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the Company for purposes of ss.18 of the Securities Exchange Act of 1964, as amended. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 63 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Abraxas Petroleum Corporation and Subsidiaries Independent Auditors' Report for the year ended December 31, 2003..........F-2 Independent Auditors' Reports for the years ended December 31, 2001 and 2002................................................................F-3 Consolidated Balance Sheets at December 31, 2002 and 2003..................F-4 Consolidated Statements of Operations for the years ended December 31, 2001, 2002 and 2003........................................F-6 Consolidated Statements of Stockholders' Deficit for the years ended December 31, 2001, 2002 and 2003.......................................F-7 Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2002 and 2003........................................F-9 Consolidated Statements of Other Comprehensive Income (loss) for the years ended December 31, 2001, 2002 and 2003... ................F-11 Notes to Consolidated Financial Statements ................................F-12 Grey Wolf Exploration Inc. Auditors' Reports for the years ended December 31, 2001 and 2002...........F-47 Comments by Auditors' for US readers on Canada - US reporting differences..F-48 Balance Sheet at December 31, 2002.........................................F-49 Statements of Earnings and Retained Earnings for the years ended December 31, 2002 and 2001 .............................................F-50 Statements of Cash Flows for the years ended December 31, 2002 and 2001...F-51 Notes to Financial Statements..............................................F-52 F-1 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Abraxas Petroleum Corporation We have audited the accompanying consolidated balance sheet of Abraxas Petroleum Corporation (the "Company") as of December 31, 2003, and the related consolidated statements of operations, stockholders' deficit, and cash flows and other comprehensive income for the year ended December 31, 2003. 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 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 audit provides a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Abraxas Petroleum Corporation at December 31, 2003, and the results of its operations and its cash flows for the year ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1 to the consolidated financial statements, as of January 1, 2003, the Company changed its method of accounting for asset retirement obligations. /s/BDO Seidman, LLP Dallas, Texas February 13, 2004 F-2 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Abraxas Petroleum Corporation We have audited the accompanying consolidated balance sheet of Abraxas Petroleum Corporation and Subsidiaries (the "Company") as of December 31, 2002, and the related consolidated statements of operations, stockholders' deficit, and cash flows and other comprehensive income for each of the two years in the period ended December 31, 2002. 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, 2002, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the financial statements, on January 23, 2003, the Company sold all of the outstanding common stock of two wholly owned subsidiaries, Canadian Abraxas Petroleum Limited and Grey Wolf Exploration, Inc., repaid certain debt, and also entered into an agreement to exchange cash, new debt and common stock of the Company for certain other debt. As discussed in Note 19 to the financial statements, the accompanying 2001 and 2002 financial statements have been restated. /s/DELOITTE & TOUCHE LLP San Antonio, Texas March 10, 2003 (July 18, 2003, as to Note 19 and the first paragraph of "New Accounting Pronouncements" in Note 1) F-3
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS ASSETS December 31 -------------------------------------- 2002 2003 ------------------ ------------------- (Dollars in thousands) Current assets: Cash ................................................... $ 4,882 $ 493 Accounts receivable: Joint owners ....................................... 2,215 1,360 Oil and gas production sales ....................... 7,466 5,873 Other .............................................. 364 1,090 ------------------ ------------------- 10,045 8,323 Equipment inventory .................................... 1,014 782 Other current assets ................................... 1,240 572 ------------------ ------------------- Total current assets.................................. 17,181 10,170 Property and equipment: Oil and gas properties, full cost method of accounting: Proved ............................................. 521,995 325,222 Unproved, not subject to amortization .............. 7,052 4,304 Other property and equipment ......................... 44,189 4,540 ------------------ ------------------- Total .......................................... 573,236 334,066 Less accumulated depreciation, depletion, and amortization ....................................... 422,842 222,503 ------------------ ------------------- Total property and equipment - net ................. 150,394 111,563 Deferred financing fees net ............................... 5,671 4,410 Deferred income taxes...................................... 7,820 - Other assets .............................................. 359 294 ------------------ ------------------- Total assets ........................................... $ 181,425 $ 126,437 ================== =================== See accompanying notes to consolidated financial statements
F-4
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (CONTINUED) LIABILITIES AND STOCKHOLDERS' DEFICIT December 31 -------------------------------------- 2002 2003 ------------------ ------------------- (Dollars in thousands) Current liabilities: Accounts payable .......................................... $ 9,687 $ 6,756 Joint interest oil and gas production payable ............. 2,432 2,290 Accrued interest .......................................... 6,009 2,340 Other accrued expenses .................................... 1,162 1,228 Current maturities of long-term debt ...................... 63,500 - ------------------ ------------------- Total current liabilities................................ 82,790 12,614 Long-term debt ............................................... 236,943 184,649 Future site restoration ..................................... 3,946 1,377 Stockholders' equity (deficit): Common stock, par value $.01 per share - authorized 200,000,000 shares; issued 30,145,280 and 36,024,308 at December 31, 2002 and 2003 respectively............ 301 360 Additional paid-in capital ................................ 136,830 141,835 Receivables from stock sale................................ (97) (97) Accumulated deficit ...................................... (269,621) (213,701) Treasury stock, at cost, 165,883 shares.................... (964) (964) Accumulated other comprehensive income (loss).............. (8,703) 364 ------------------ ------------------- Total stockholders' deficit................................... (142,254) (72,203) ------------------ ------------------- Total liabilities and stockholders' deficit................ $ 181,425 $ 126,437 ================== =================== See accompanying notes to consolidated financial statements
F-5
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31 ---------------------------------------------------------- 2001 2002 2003 ---------------------------------------------------------- (In thousands except per share data) Revenues: Oil and gas production revenues ......................... $ 73,201 $ 50,862 $ 38,105 Gas processing revenues.................................. 2,438 2,420 133 Rig revenues ............................................ 756 635 663 Other .................................................. 848 403 118 -------------------------------------------------------- 77,243 54,320 39,019 Operating costs and expenses: Lease operating and production taxes .................... 18,616 15,240 9,599 Depreciation, depletion, and amortization ............... 32,484 26,539 10,803 Proved property impairment .............................. 2,638 115,993 - Rig operations .......................................... 702 567 609 General and administrative .............................. 6,445 6,884 5,360 Stock-based compensation................................. (2,767) - 1,106 -------------------------------------------------------- 58,118 165,223 27,477 -------------------------------------------------------- Operating income (loss)..................................... 19,125 (110,903) 11,542 Other (income) expense: Interest income ......................................... (78) (92) (30) Amortization of deferred financing fees ................. 2,268 2,095 1,678 Interest expense ........................................ 31,523 34,150 16,955 Financing costs.......................................... - 967 4,406 Loss on sale of equity investment ....................... 845 - - Gain on sale of foreign subsidiaries..................... - - (68,933) Other ................................................... 207 201 774 -------------------------------------------------------- 34,765 37,321 (45,150) -------------------------------------------------------- Income (loss) before cumulative effect of accounting change and taxes................................................ (15,640) (148,224) 56,692 Income tax expense (benefit): Current ................................................. 505 - - Deferred ................................................ 1,897 (29,697) 377 Minority interest in income of foreign subsidiary (2001 prior to purchase)....................................... 1,676 - - Cumulative effect of accounting change...................... - - 395 -------------------------------------------------------- Net income (loss)........................................ $ (19,718) $ (118,527) $ 55,920 ======================================================== Basic earnings (loss)per common share: Net earnings (loss)................................... $ (0.76) $ (3.95) $ 1.59 Cumulative effect of accounting change................ - - (0.01) -------------------------------------------------------- Net income (loss) per common share - basic .............. $ (0.76) $ (3.95) $ 1.58 ======================================================== Diluted earnings (loss) per common share: Net earnings (loss)................................... $ (0.76) $ (3.95) $ 1.56 Cumulative effect of accounting change................ - - (0.01) -------------------------------------------------------- Net income (loss) per common share - diluted............ $ (0.76) $ (3.95) $ 1.55 ======================================================== See accompanying notes to consolidated financial statements
F-6
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT (In thousands except share amounts) Common Stock Treasury Stock Additional -------------------------------------------- Paid-In Shares Amount Shares Amount Capital ----------- ------------------------------------------------- Balance at December 31, 2000 . 22,759,852 $ 227 165,883 $ (964) $ 130,409 Comprehensive income (loss) Net loss .................... -- -- -- -- Other comprehensive income: Hedge loss .............. -- -- -- -- Foreign currency translation adjustment. -- -- -- -- adjustment Comprehensive income ...... (28,480) (loss) Stock-based compensation expense ................. -- -- -- (2,767) Issuance of common stock for contingent value rights .................. 3,383,488 34 -- -- (34) Issuance of common stock and stock options for acquisition of minority interest in .... Old Grey Wolf Exploration, Inc. ....... 3,990,565 40 -- -- 9,206 Stock options exercised ... 8,375 -- -- 16 -- ---------- --------- --------- ----------- ------------ Balance at December 31, 2001 . 30,145,280 $ 301 165,883 $ (964) $ 136,830 Comprehensive income (loss): Net loss .................. -- -- -- -- -- Other comprehensive income: Hedge income .......... -- -- -- -- -- Foreign currency translation ......... -- -- -- -- -- adjustment Comprehensive income (loss) ---------- ------- --------- ----------- ------------ Balance at December 31, 2002.. 30,145,280 $ 301 165,883 $ (964) $ 136,830
Accumulated Other Recivables Accumuated Comprehensive From Deficit Income (loss) Stock Sale Total ------------- -------------- ------------- ---------- Balance at December 31, 2000 . $ (131,376) $ (4,799) $ (97) $ (6,600) Comprehensive income (loss): Net loss .................... (19,718) -- -- (19,718) Other comprehensive income: Hedge loss .............. -- (566) -- (566) Foreign currency translation adjustment. -- (8,196) -- (8,196) adjustment --------- Comprehensive income (loss).. (24,480) Stock-based compensation expense ................. -- -- -- (2,767) Issuance of common stock for contingent value rights .................. -- -- -- -- Issuance of common stock and stock options for acquisition of minority interest in Old Grey Wolf Exploration, Inc. ........ -- -- -- 9,246 Stock options exercised ... -- -- -- 16 ------------- -------------- ------------- ---------- Balance at December 31, 2001 . $(151,094) $ (13,561) $ (97) $ (28,585) Comprehensive income (loss): Net loss ................. . (118,527) -- -- (118,527) Other comprehensive income: Hedge income .......... -- 566 -- 566 Foreign currency translation ......... adjustment -- 4,292 -- 4,292 ----------- Comprehensive income (loss) (113,669) ------------- -------------- ------------- ---------- Balance at December 31, 2002. . $ (269,621) $ (8,703) $ (97) $ (142,254)
F-7
ABRAXAS PETROLEUM CORPORATIONRIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT (continued) (In thousands except share amounts) Common Stock Treasury Stock Additional -------------------------------------------- Paid-In Shares Amount Shares Amount Capital ----------- --------- ---------- ----------- ----------------- Balance at December 31, 2002.. 30,145,280 $ 301 165,883 $ (964) $136,830 Comprehensive income (loss): Net income ............. -- -- -- -- -- Other comprehensive income (loss): Foreign currency translation adjustment ........ -- -- -- -- -- Comprehensive income .... Stock-based compensation expense ............... -- -- -- -- 1,106 Stock options exercised . 129,352 1 -- -- 84 Stock issued for acquisition of Wind ... River Resources 106,977 1 -- -- 91 Stock issued in connection with exchange offer 5,642,699 57 -- -- 3,724 ----------- --------- ---------- ----------- ----------------- Balance at December 31, 2003. 36,024,308 $ 360 165,883 $ (964) $ 141,835 =========== ========= ========== =========== =================
Accumulated Other Recivables Accumuated Comprehensive From Deficit Income (loss) Stock Sale Total ------------- -------------- ------------- ---------- Balance at December 31, 2002. $ (269,621) $ (8,703) $ (97) $ (142,254) Comprehensive income (loss): Net income .......... 55,920 -- -- 55,920 Other comprehensive income (loss): Foreign currency translation adjustment ........ -- 9,067 -- 9,067 ---------- Comprehensive income .... 64,987 Stock-based compensation expense ............... -- -- -- 1,106 Stock options exercised . -- -- -- 85 Stock issued for acquisition of Wind ... River Resources -- -- -- 92 Stock issued in connection with exchange offer......... -- -- -- 3,781 ------------- -------------- ------------- ---------- Balance at December 31, 2003 $ (213,701) $ 364 $ (97) $ (72,203) ============= ============== ============= ==========
See accompanying notes to consolidated financial statements. F-8
Abraxas Petroleum Corporation CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31 ---------------------------------------------------------------- 2001 2002 2003 ---------------------------------------------------------------- (In thousands) Operating Activities Net income (loss) ................................... $ (19,718) $ (118,527) $ 55,920 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Minority interest in income of foreign subsidiary 1,676 - - Loss on sale of equity investment................ 845 - - (Gain) on sale of foreign subsidiaries........... - - (68,933) Depreciation, depletion, and amortization ................................ 32,484 26,539 10,803 Non-cash interest and financing cost............ - - 16,422 Proved property impairment ..................... 2,638 115,993 - Deferred income tax expense (benefit)........... 1,897 (29,697) 377 Amortization of deferred financing fees......... 2,268 2,095 1,678 Stock-based compensation ....................... (2,767) - 1,106 Changes in operating assets and liabilities: Accounts receivable ......................... 12,693 (2,247) (1,446) Equipment inventory ......................... (76) 201 78 Other ...................................... (106) 126 295 Accounts payable ............................ (14,848) (2,775) 3,417 Accrued expenses ............................ (723) (44) 4,133 ------------------ ------------------ ------------------ Net cash provided by (used) in operations............ 16,263 (8,336) 23,850 Investing Activities Capital expenditures, including purchases and development of properties .................... (57,056) (38,912) (18,349) Proceeds from sale of oil and gas properties........................................ 28,938 33,876 - Acquisition of minority interest..................... (2,679) - - Proceeds from sale of foreign subsidiaries.......... - - 85,810 ------------------ ------------------ ------------------ Net cash provided by (used ) in investing activities. (30,797) (5,036) 67,461
F-9
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) Years Ended December 31 ---------------------------------------------------------------- 2001 2002 2003 ---------------------------------------------------------------- (In thousands) Financing Activities Proceeds from issuance of common stock............... 16 - 177 Proceeds from long-term borrowings .................. 29,995 20,551 43,342 Payments on long-term borrowings .................... (9,326) (8,176) (138,544) Deferred financing fees ............................. - (1,539) (597) ------------------ ------------------ ------------------ Net cash (used in) provided by financing activities.. 20,685 10,836 (95,622) ------------------ ------------------ ------------------ Increase (decrease) in cash ......................... 6,151 (2,536) (4,311) Effect of exchange rate changes on cash.............. (550) (187) (78) ------------------ ------------------ ------------------ Increase (decrease) in cash ......................... 5,601 (2,723) (4,389) Cash at beginning of year ........................... 2,004 7,605 4,882 ------------------ ------------------ ------------------ Cash at end of year.................................. $ 7,605 $ 4,882 $ 493 ================== ================== ================== Supplemental Disclosures Supplemental disclosures of cash flow information: Interest paid .......................... $ 31,752 $ 34,154 $ 4,279 ================== ================== ================== Taxes paid.............................. $ 505 $ - $ - ================== ================== ================== Supplemental schedule of non-cash investing and financing activities: 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. 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 Old Grey Wolf. (See Note 4.) 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 CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) Years Ended December 31, 2001 2002 2003 --------------------------------------------------------- (In thousands) Net income (loss)............................................ $ (19,718) $ (118,527) $ 55,920 Other Comprehensive income (loss): Hedging derivatives (net of tax) - See Note 16 (566) - Reclassification adjustment for settled hedge contracts, net of taxes................................................ - 2,556 - Change in fair market value of outstanding hedge positions net of taxes ............................................... - (1,990) - ------------------- ------------------ ------------------ - 566 - Foreign currency translation adjustment Reclassification of foreign currency translation adjustment relating to the sale of foreign subsidiaries.............. - - 4,632 Effect of change in exchange rate........................... - - 4,435 ------------------- ------------------ ------------------ Other comprehensive income (loss)................................ (8,762) 4,858 9,067 ------------------- ------------------ ------------------ Comprehensive income (loss)...................................... $ (28,480) $ (113,669) $ 64,987 =================== ================== ================== See accompanying notes to consolidated financial statements.
F-11 ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 western Canada. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc. ("New Grey Wolf"). In January 2003, the Company sold all of the common stock of its wholly-owned foreign subsidiaries, Canadian Abraxas Petroleum Limited ("Canadian Abraxas") and Grey Wolf Exploration Inc. ("Old Grey Wolf"). Certain oil and gas properties were retained and transferred into New Grey Wolf which was incorporated in January 2003. The operations of Canadian Abraxas and Old Grey Wolf are included in the consolidated financial statements through January 23, 2003. New Grey Wolf's assets and liabilities are translated to U.S. dollars at period-end exchange rates. Income and expense items are translated at average rates of exchange prevailing during the period. Translation adjustments are accumulated as a separate component of shareholders' equity. Use of Estimates The preparation of consolidated 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 consolidated 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 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. Cash and Equivalents Cash and cash equivalents includes cash on hand, demand deposits and short-term investments with original maturities of three months or less. Accounts Receivable Accounts receivable are reported net of an allowance for doubtful accounts of approximately $77,000 and $11,000 at December 31, 2002 and 2003, respectively. The allowance for doubtful accounts is determined based on the Company's historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible. F-12 Equipment Inventory Equipment inventory principally consists of casing, tubing, and compression equipment and is carried at cost. 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 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, as adjusted for asset retirement obligations, 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. 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 2001, 2002 and 2003 the Company capitalized $164,000, $152,000 and $49,000 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 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. Hedging The Company periodically enters into agreements to hedge the risk of future crude oil and natural gas price fluctuations. Such agreements are primarily in the form of price floors and collars, which limit the impact of price fluctuations with respect to the Company's sale of crude oil and natural gas. The Company does not enter into speculative hedges. 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," 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 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," (APB No. 25) 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. F-13 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. The Company recognized a credit of $2.8 million during 2001 as stock-based compensation. The credit for the year ended December 31, 2001 was due to a decline in the Company's common stock price. There was no stock based compensation for the year ended December 31, 2002. In January 2003, in connection with the restructuring (see note 2), the Company amended the exercise price to $0.66 on certain options with an existing exercise price greater than $0.66. The Company recognized stock-based compensation expense of approximately $1.1 million during 2003. Pro forma information regarding net income (loss) and earnings (loss) per share is required by SFAS 123, "Accounting for Stock-Based Compensation, (SFAS 123)" 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 SFAS No. 123. 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 2001, 2002 and 2003, risk-free interest rates of 3.5%, 1.50% and 1.5%, respectively; dividend yields of -0-%; volatility factors of the expected market price of the Company's common stock of .35, and a weighted-average expected life of the option of ten years. 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:
Year Ended December 31 ---------------------------------------------------------------- 2001 2002 2003 ------------------- ----------------- ----------------- Net income (loss) as reported $ (19,718) $ (118,527) $ 55,920 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects (2,767) - 1,106 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (1,284) (670) (228) ------------------- ----------------- ----------------- Pro forma net income (loss) $ (23,769) $ (119,197) $ 56,798 =================== ================= ================= Earnings (loss) per share: Basic - as reported $ (0.76) $ (3.95) $ 1.58 =================== ================= ================= Basic - pro forma $ (0.92) $ (3.98) $ 1.61 =================== ================= ================= Diluted - as reported $ (0.76) $ (3.95) $ 1.55 =================== ================= ================= Diluted - pro forma $ (0.92) $ (3.98) $ 1.57 =================== ================= =================
Foreign Currency Translation The functional currency for Canadian Abraxas and Grey Wolf (Old and New) 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 the consolidated financial statement of stockholders' deficit. F-14 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 Company is subject to extensive Federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable. 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. The Company had no material gas imbalances at December 31, 2003. 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 deferred 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 A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of such mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights held under lease or other contractual arrangement associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $3.1 million and $4.2 million at December 31, 2002 and December 31, 2003, respectively, out of oil and gas properties and into a separate intangible assets line item. The Company's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full-cost accounting rules. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 is effective for us January 1, 2003. SFAS 143 requires that the fair value of a liability for an asset's retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. F-15 The Company adopted SFAS 143 effective January 1, 2003. For the year ended December 31, 2003 the Company recorded a charge of $395,341 for the cumulative effect of the change in accounting principle and a liability of $1.3 million. During 2003, the Company charged approximately $379,000 to expense related to the accretion of the liability. The impact on each of the prior periods was not material. The following table summarizes the Company's asset retirement obligation transactions during the following years:
2003 2002 2001 ----------------------- ------------------- --------------------- Beginning asset retirement obligation................ $ 3,946 $ 4,056 $ 4,305 Additions related to new properties.................. 973 196 - Deletions related to property disposals.............. (3,921) (306) (249) Accretion expense.................................... 379 - - ----------------------- ------------------- --------------------- Ending asset retirement obligation................... $ 1,377 $ 3,946 $ 4,056 ======================= =================== =====================
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). Effective January 1, 2002, the Company adopted SFAS 144. SFAS 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 144, among other things, changes the criteria that have to be met to classify an asset as held-for-sale and requires that operating losses from discontinued operations be recognized in the period that the losses are incurred rather than as of the measurement date. This new standard had no impact on the Company's consolidated financial statements for the year ended December 31, 2003. In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS 146). SFAS 146 requires costs associated with exit of disposal activities to be recognized when they are incurred rather than at the date of commitment to an exit or disposal plan. The Company is currently evaluating the impact the standard will have on its results of operations and financial condition. The effective date of this standard has not been determined by the FASB. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 149, among other things, clarifies the circumstances under which a contract with an initial net investment meets the characteristic of a derivative and amends the definition of an "underlying" to conform it to language used in FIN 45. SFAS 149 is effective for contracts entered into or modified after June 30, 2003. The Company adopted this statement effective July 1, 2003. Implementation of this new standard did not have an effect on the Company's consolidated financial position or results of operations. In November 2002 the FASB issued FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees that it has issued, including loan guarantees such as standby letters of credit. It also requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligations it has undertaken in issuing the guarantee. The Interpretation does not specify the subsequent measurement of the guarantor's recognized liability over the term of the related guarantee. The guidance in FIN 45 does not apply to certain guarantee contracts, such as those issued by insurance companies or for a lessee's residual value guarantee embedded in a capital lease. The provisions related to recognizing a liability at inception of the guarantee for the fair value of the guarantor's obligations would not apply to product warranties or to guarantees accounted for as derivatives. The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002, regardless of the guarantor's fiscal year-end. FIN 45 specifies additional disclosures effective for financial statements of interim or annual periods ending after December 15, 2002. This new standard did not have an effect on the Company's consolidated financial position or results of operations. In January 2003 the FASB issued FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable-Interest Entities (VIEs".) FIN 46 establishes the definition of VIEs to encompass a broader group of entities than those previously considered special-purpose entities (SPEs). FIN 46 specifies the criteria under which it is appropriate for an investor to consolidate VIEs; in order for an investor to consolidate a VIE, the entity must fall within the definition of VIE and the investor must fall within the definition of primary beneficiary, both newly defined terms under this interpretation. The revised effective date of FIN 46 for public companies with VIEs meeting certain conditions will be the end of the first interim or annual period ending after F-16 December 15, 2003. In December 2003 the FASB issued FASB Interpretation no. 46(R), which expanded and clarified the guidelines of FIN 46. This new standard did not have an effect on the Company's consolidated financial position or results of operations. In May 2003, the FASB issued SFAS No. 150, entitled "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" (SFAS 150). This statement is effective for financial instruments entered into or modified after May 31, 2003, and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. The Company has no financial instruments affected by SFAS 150, therefore adoption by the Company as of July 1, 2003 will not impact the Company's financial statements. 2. Restructuring transactions In January 2003, the Company completed the following restructuring transactions: o The closing of the sale of the capital stock of Canadian Abraxas Petroleum and Old Grey Wolf, to a Canadian royalty trust for approximately $138 million. o The closing of a new senior credit agreement consisting of a term loan facility of $4.2 million and a revolving credit facility of up to $50 million with an initial borrowing base of $49.9 million, of which $42.5 million was used to fund the exchange offer described below and the remaining availability will be used to fund the continued development of our existing crude oil and natural gas properties. o The closing of an exchange offer, pursuant to which Abraxas paid $264 in cash and issued $610 principal amount of new 11 1/2 % Secured Notes due 2007, Series A, referred to herein as New Notes, and 31.36 shares of Abraxas common stock for each $1,000 in principal amount of the outstanding 11 1/2 % Senior Secured Notes due 2004, Series A, and 11 1/2 % Senior Notes due 2004, Series D, issued by Abraxas and Canadian Abraxas, which were tendered and accepted in the exchange offer. An aggregate of approximately $179.9 million in principal amount of the notes were tendered in the exchange offer and the remaining $11.1 million of notes not tendered were redeemed. o The repayment of Abraxas' 12? % Senior Secured Notes due 2003, principal amount of $63.5 million, plus accrued interest. o The repayment of Old Grey Wolf's senior secured credit facility with Mirant Canada Energy Capital Ltd. (Mirant Canada Facility) in the amount of approximately $46.3 million. On February 23, 2004, the Company entered into an amendment to our existing senior credit agreement providing for two revolving credit facilities and a new non-revolving credit facility as described below. Subject to earlier termination on the occurrence of events of default or other events, the stated maturity date for these credit facilities is February 1, 2007. In the event of an early termination, we will be required to pay a prepayment premium, except in the limited circumstances described in the amended senior credit agreement. First Revolving Credit Facility. Lenders under the amended senior credit agreement have provided Abraxas a revolving credit facility with a maximum borrowing base of up to $20 million. The Company's current borrowing base under this revolving credit facility is the full $20.0 million, subject to adjustments based on periodic calculations and mandatory prepayments under the senior credit agreement. The Company has borrowed $6.6 million under this revolving credit facility, which was used to refinance principal and interest on advances under it's preexisting revolving credit facility under the senior credit agreement, and to pay certain fees and expenses relating to the transaction. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 1.125%. Second Revolving Credit Facility. Lenders under the amended senior credit agreement have provided a second revolving credit facility, with a maximum borrowing of up to $30 million. This revolving credit facility is not subject to a borrowing base. The Company has borrowed $30.0 million under this revolving credit facility, which was used to refinance principal and interest on advances under our preexisting revolving credit facility, and to pay certain transaction fees and expenses. Outstanding amounts under this revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 3.00%. Non-Revolving Credit Facility. The Company has borrowed $15.0 million pursuant to a non-revolving credit facility, which was used to repay the preexisting term loan under it's senior credit agreement, to refinance principal and interest on advances under the preexisting revolving credit facility, and to pay certain transaction fees and expenses. This non-revolving credit facility is not subject to a borrowing base. Outstanding amounts under this credit facility bear interest at the prime rate announced by Wells Fargo Bank, N.A. plus 8.00%. F-17 Covenants. Under the amended senior credit agreement, we are subject to customary covenants and reporting requirements. Certain financial covenants require us to maintain minimum ratios of consolidated EBITDA (as defined in the amended senior credit agreement) to adjusted fixed charges (which includes certain capital expenditures), minimum ratios of consolidated EBITDA to cash interest expense, a minimum level of unrestricted cash and revolving credit availability, minimum hydrocarbon production volumes and minimum proved developed hydrocarbon reserves. In addition, if on the day before the end of each fiscal quarter the aggregate amount of our cash and cash equivalents exceeds $2.0 million, we are required to repay the loans under the amended senior credit agreement in an amount equal to such excess. The amended senior credit agreement also requires us to enter into hedging agreements on not less than 40% or more than 75% of our projected oil and gas production. We are also required to establish deposit accounts at financial institutions acceptable to the lenders and we are required to direct our customers to make all payments into these accounts. The amounts in these accounts will be transferred to the lenders upon the occurrence and during the continuance of an event of default under the amended senior credit agreement. In addition to the foregoing and other customary covenants, the amended senior credit agreement contains a number of covenants that, among other things, restrict our ability to: o incur additional indebtedness; o create or permit to be created liens on any of our properties; o enter into change of control transactions; o dispose of our assets; o change our name or the nature of our business; o make guarantees with respect to the obligations of third parties; o enter into forward sales contracts; o make payments in connection with distributions, dividends or redemptions relating to our outstanding securities, or o make investments or incur liabilities. Security. The obligations of Abraxas under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of Abraxas' assets, including all crude oil and natural gas properties. Guarantees. The obligations of Abraxas under the amended senior credit agreement continue to be guaranteed by Abraxas' subsidiaries, Sandia Oil & Gas, Sandia Operating, Wamsutter, Grey Wolf, Western Associated Energy and Eastside Coal. The guarantees under the amended senior credit agreement continue to be secured by a first lien security interest in substantially all of the guarantors' assets, including all crude oil and natural gas properties. Events of Default. The amended senior credit agreement 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 our financial condition. The following presents the summarized results of operations for the years ended December 31, 2001, 2002, and for the period ended January 23, 2003, for the Canadian properties which were not retained after the transaction in January 2003.
Year ended December 31, 2001 2002 2003 -------- -------- -------- Total revenue ................................. $ 41,468 $ 32,013 $ 3,275 ======== ======== ======== Income (loss) from operations before income tax (102) (87,378) 1,250 Income tax expense (benefit) .................. 1,897 (29,697) 377 Minority interest in income ................... (1,676) -- -- -------- -------- -------- Income (loss) from operations ................. $ (3,675) $(57,681) $ 873 ======== ======== ========
F-18 Assets and liabilities related to the Canadian properties which were not retained after the January 2003 transaction: December 31, 2002 -------- Assets: Cash............................................ $ 4,325 Accounts receivable............................. 4,016 Net property and equipment...................... 54,468 Other........................................... 11,438 -------- $ 74,247 -------- Liabilities: Accounts payable and accrued liabilities........ $ 7,320 Long-tern debt.................................. 45,964 Other........................................... 3,413 -------- $ 56,697 -------- Included in the loss from operations shown above is interest expense of $7.6 million and $9.5 million, and general and administrative expense of $1.5 million and $1.7 million for the years ended December 31, 2001 and 2002, respectively. The interest expense represents the amounts relating to an Old Grey Wolf senior credit facility which was repaid in conjunction with the transactions described above and the amounts related to the balance of certain notes (approximately $52.6 million) which had historically been reflected by Canadian Abraxas. 3. Long-Term Debt As described in Note 2, the First Lien Notes were redeemed in January 2003. The Old Notes and the Second Lien Notes were either redeemed or exchanged for cash, common stock and New Notes in January 2003. Additionally, the 9.5% Mirant Canada Energy Capital, Ltd. credit facility, with a balance outstanding at December 31, 2002 of $45.9 million, was repaid in connection with the sale of the common stock of Old Grey Wolf in January 2003. The following is a brief description of the Company's debt as of December 31, 2002 and 2003, respectively:
December 31 -------------------------------- 2002 2003 -------------------------------- (in thousands) 11.5% Senior Notes due 2004 ("Old Notes") ......................... $ 801 $ - 12.875% Senior Secured Notes due 2003 ("First Lien Notes") ........ 63,500 - 11.5% Second Lien Notes due 2004 ("Second Lien Notes")............. 190,178 - 9.5% Senior Credit Facility ("Grey Wolf Facility") providing for borrowings up to approximately US $96 million (CDN $150 million). Secured by the assets of Old Grey Wolf and non-recourse to Abraxas....................................... 45,964 - 11.5% Secured Notes due 2007 ("New Notes")......................... - 137,258 (a) Senior Credit Agreement ........................................... - 47,391 --------------------------------- 300,443 184,649 Less current maturities ........................................... 63,500 - --------------------------------- $ 236,943 $ 184,649 =================================
(a) After the transactions described in Note 2, for financial reporting purposes, the New Notes were reflected at the carrying value of the Second Lien Notes and Old Notes prior to the exchange of $191.0 million, net of the cash offered in the exchange of $47.5 million and net of the fair market value related to equity of $3.8 million offered in the exchange transaction. The face amount of the New Notes is $120.5 million at December 31, 2003 including $10.8 million in new notes issued for interest. Old Notes. Interest on the Old Notes was 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 were redeemable, in whole or in part, at the option of the Company. First Lien Notes. Interest on the First Lien Notes was payable semi-annually in arrears on March 15 and September 15 of each year at the rate of 12.875% per annum. Second Lien Notes. Interest on the Second Lien Notes was payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2000 at the rate of 11.5% per annum. F-19 New Notes - 11 1/2% Secured Notes. The New Notes accrue interest from the date of issuance, at a fixed annual rate of 11 1/2%, payable in cash semi-annually on each May 1 and November 1, commencing May 1, 2003, provided that, if we fail, or are not permitted pursuant to our new senior secured credit agreement or the intercreditor agreement between the trustee under the indenture for the New Notes and the lenders under the new senior secured credit agreement, to make such cash interest payments in full, we will pay such unpaid interest in kind by the issuance of additional New Notes with a principal amount equal to the amount of accrued and unpaid cash interest on the New Notes plus an additional 1% accrued interest for the applicable period. Upon an event of default, the New Notes accrue interest at an annual rate of 16.5%. The New Notes are secured by a second lien or charge on all of our current and future assets, including, but not limited to, all of our crude oil and natural gas properties. All of Abraxas' current subsidiaries, Sandia Oil & Gas, Sandia Operating (a wholly-owned subsidiary of Sandia Oil & Gas), Wamsutter, New Grey Wolf, Western Associated Energy and Eastside Coal, are guarantors of the New Notes, and all of Abraxas' future subsidiaries will guarantee the New Notes. If Abraxas cannot make payments on the New Notes when they are due, the guarantors must make them instead. The New Notes and related guarantees o are subordinated to the indebtedness under the senior credit agreement; o rank equally with all of Abraxas' current and future senior indebtedness; and o rank senior to all of Abraxas' current and future subordinated indebtedness, in each case, if any. The New Notes are subordinated to amounts outstanding under the new senior secured credit agreement both in right of payment and with respect to lien priority and are subject to an intercreditor agreement. Abraxas may redeem the New Notes, at its option, in whole at any time or in part from time to time, at redemption prices expressed as percentages of the principal amount set forth below. If Abraxas redeems all or any New Notes, it must also pay all interest accrued and unpaid to the applicable redemption date. The redemption prices for the New Notes during the indicated time periods are as follows: Period Percentage From January 24, 2004 to June 23, 2004................................97.1674% From June 24, 2004 to January 23, 2005................................98.5837% Thereafter...........................................................100.0000% Under the indenture, we are subject to customary covenants which, among other things, restrict our ability to: o...borrow money or issue preferred stock; o pay dividends on stock or purchase stock; o make other asset transfers; o transact business with affiliates; o sell stock of subsidiaries; o engage in any new line of business; o impair the security interest in any collateral for the notes; o use assets as security in other transactions; and o sell certain assets or merge with or into other companies. In addition, we are subject to certain financial covenants including covenants limiting our selling, general and administrative expenses and capital expenditures, a covenant requiring Abraxas to maintain a specified ratio of consolidated EBITDA, as defined in the agreements, to cash interest and a covenant requiring Abraxas to permanently, to the extent permitted, pay down debt under the new senior secured credit agreement and, to the extent permitted by the new senior secured credit agreement, the New Notes or, if not permitted, paying indebtedness under the new senior secured credit agreement. F-20 The indenture 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 our financial condition. Senior Credit Agreement. In connection with the financial restructuring, Abraxas entered into a new senior credit agreement providing a term loan facility and a revolving credit facility which was amended in February 2004. A summary description of the senior credit agreement as amended, is set forth in Note 2. 4. Acquisitions and Divestitures Acquisition of Minority Interest in Old Grey Wolf In September 2001, the Company completed a tender offer for the minority interest in Old 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 Old 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. 5. Property and Equipment The major components of property and equipment, at cost, are as follows:
Estimated December 31 ---------------------------------- Useful Life 2002 2003 ----------------- ---------------- ----------------- Years (In thousands) Land, buildings, and improvements .............. 15 $ 331 $ 331 Crude oil and natural gas properties ........... - 529,047 329,526 Natural Gas Processing.......................... 18 38,735 - Equipment and other ............................ 7 5,123 4,209 ---------------- ----------------- $ 573,236 $ 334,066 ================ =================
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. 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, 2001, 2002 and 2003, the Company did not purchase any shares of its common stock for treasury stock. F-21 7. Stock Option Plans and Warrants Stock Options The Company grants options to its officers, directors, and other 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 shares. The additional shares were necessary to accommodate the grant of Abraxas options to Old Grey Wolf option holders in connection with the acquisition of the minority interest in Old Grey Wolf in September 2001 (see Note 4), 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 5.7 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, 2003 approximately 2.3 million options remain available for grant. A summary of the Company's stock option activity, and related information for the three years ended December 31, follows:
2001 2002 2003 ----------------------------- ----------------------------- ----------------------------- Weighted-Average Weighted-Average Weighted-Average Options Exercise Price Options Exercise Price Options Exercise Price (000s) (000s) (1) (000s) ---------- ------------------ ---------- ------------------ --------- ------------------ Outstanding-beginning of year ................... 4,042 $ 3.37 4,942 $ 3.28 3,305 $ 1.85 Granted ................... 918 2.81 521 0.68 360 0.68 Exercised ................. (8) 1.95 - - (129) 0.66 Forfeited/Expired ......... (10) 1.79 (2,158) 4.84 (172) 1.61 ---------- ---------- --------- Outstanding-end of year ... 4,942 $ 3.28 3,305 $ 1.85 3,364 $ 0.90 ========== ========== ========= Exercisable at end of year 2,259 $ 2.65 2,136 $ 1.91 2,331 $ 0.95 ========== ========== ========= Weighted-average fair value of options granted during the year $ 1.19 $ 0.63 $ 0.38
------------------ (1) 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. The following table represents the range of option prices and the weighted average remaining life of outstanding options as of December 31, 2003:
Options outstanding Exercisable ----------------------------------------------- -------------------------------------- Weighted Weighted average average Number remaining exercise Number Weighted average Exercise price outstanding life price exercisable exercise price --------------------- ------------------ --------------- ------------ ---------------- --------------------- $0.50 - 0.97 2,761,160 6.0 $ 0.71 1,886,043 $ 0.69 $1.01 - 1.63 259,900 7.8 1.22 123,050 1.40 $2.06 - 2.21 311,958 2.1 2.07 305,979 2.06 $3.39 - 4.83 31,407 6.9 4.77 16,406 4.71
F-22 In January 2003, in connection with the financial restructuring discussed in Note 2, approximately 1.9 million options with a strike price greater that $0.66 were re-priced to $0.66. 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. There were no awards in 2001, 2002 or 2003. The Company also has adopted the Restricted Share Plan for Directors which provides for awards of common stock to non-employee 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. There were no direct awards of common stock in 2001, 2002 or 2003. Stock Warrants 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 paid cash compensation of $191,000 during 2001 under the consulting agreement. At December 31, 2003, the Company has approximately 3.3 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 --------------------------- 2002 2003 ------------- ------------- (In thousands) Deferred tax liabilities: U.S. full cost pool ..................................................... $ - $ 4,835 ------------- ------------- Total deferred tax liabilities ............................................ - 4,835 Deferred tax assets: U.S. full cost pool...................................................... 2,168 - Capital loss carryforward................................................ - 12,895 Original issue discount on certain debt obligations...................... - 22,453 Canadian full cost pool.................................................. 9,787 2,971 Depletion ............................................................... 2,778 4,856 Net operating losses ("NOL")............................................ 58,811 35,218 Investment in foreign subsidiaries....................................... 32,038 - Other ................................................................... 1,364 2,575 ------------- ------------- Total deferred tax assets ................................................. 106,946 80,968 Valuation allowance for deferred tax assets ............................... (99,126) (76,133) ------------- ------------- Net deferred tax assets ................................................... 7,820 4,835 ------------- ------------- Net deferred tax liabilities (assets) ..................................... $ (7,820) $ - ============= =============
Significant components of the provision (benefit) for income taxes are as follows:
2001 2002 2003 ----------------------------------------- Current: Federal.......................................................... $ 505 $ - $ - Foreign ......................................................... - - - ---------------------------------------- $ 505 $ - $ - =========================================
F-23
Deferred: Federal ......................................................... $ - $ - $ - Foreign ......................................................... 1,897 26,697 377 ----------------------------------------- $1,897 $ 26,697 $377 =========================================
At December 31, 2003 the Company had, subject to the limitation discussed below, $100.6 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2003 through 2022 if not utilized. In connection with the January 2003 transactions described in Note 2, certain of the loss carryforward may be utilized. At December 31, 2002, the Company was no longer permanently reinvested with respect to its foreign subsidiaries, see Note 2. As a result, the Company recorded net deferred tax assets of $32.0 million related to its investment in foreign subsidiaries, offset by an equivalent valuation allowance due to uncertainties as to the future utilization of these amounts. 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 $99.1 million and $71.3 million for deferred tax assets at December 31, 2002 and 2003, respectively. , The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:
December 31 --------------------------------------------------------------------- 2001 2002 2003 -------------------------------------------- ------------------------ (In thousands) Tax (expense) benefit at U.S. statutory rates (35%) .............. $ 5,318 $ 51,878 $ (19,842) (Increase) decrease in deferred tax asset valuation allowance .......... (4,907) (59,456) 22,993 Write-down of non-tax basis assets.... (2,194) (7,009) - Higher effective rate of foreign operations.......................... (136) 7,349 (2,835) Percentage depletion ................. 596 683 - Investment in foreign subsidiaries .. - 35,604 - Other ................................ (1,079) 648 (693) -------------------------------------------- ------------------------ $ (2,402) $ 29,697 $ (377) ============================================ ========================
9. Related Party Transactions Accounts receivable - Other includes approximately $51,211 and $35,558 as of December 31, 2002 and 2003, respectively, representing amounts due from officers relating to advances made to employees. On July 29, 2003 the Company acquired all of the shares of the capital stock of Wind River Resources Corporation which owned an airplane. The sole shareholder of Wind River was the Company's President. The consideration for the purchase was 106,977 shares of Abraxas common stock and $35,000 in cash. Simultaneously with this transaction, the airplane was sold. The airplane had previously been made available to Abraxas' employees for business use. The Company paid Wind River a total of $314,000, $345,000 and $132,000 in 2001, 2002 and 2003, through July 29, respectively, for Wind River's operating cost associated with the Company's use of the plane. 10. Commitments and Contingencies Operating Leases During the years ended December 31, 2001, 2002 and 2003 the Company incurred rent expense related to leasing office facilities of approximately $519,000, $236,000 and $464,000 respectively. Future minimum rental payments are as follows at December 31, 2003. 2004............................................. $ 416,000 2005............................................. 412,000 F-24 2006............................................. 223,000 2007............................................. 161,000 Thereafter....................................... 161,000 ------------------ $ 1,373,000 ================== Litigation and Contingencies In 2001 the Company and a partnership were named in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserts breach of contract, fraud and negligent misrepresentation by the Company 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 2002 the Company recorded $201,000 in other expense representing its share of the ongoing legal cost related to this matter. In 2003, Abraxas and Leam Drilling Systems each filed suit against the other relating to certain drilling services that Leam contracted to provide Abraxas. Abraxas believes that the services were provided in a grossly negligent manner and that Leam committed fraud. Leam has asserted that Abraxas failed to pay approximately $639,000 for services rendered. The cases are pending in Bexar County and Ward County, Texas. 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, 2003, 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. 11. Earnings per Share Basic earnings (loss) per share excludes any dilutive effects of options, warrants and convertible securities and is computed by dividing income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings (loss) per share are computed similar to basic, however diluted earnings per share reflects the assumed conversion of all potentially dilutive securities. The following table sets forth the computation of basic and diluted earnings per share:
2001 2002 2003 -------------------------------------------------------- Numerator: Net income (loss) before effect of accounting change ......................................... $ (19,718,000) $ (118,527,000) $ 56,315,000 Cumulative effect of accounting change........... - - (395,000) -------------------------------------------------------- $ (19,718,000) $ (118,527,000) 55,920,000 Denominator: Denominator for basic earnings per share - weighted-average shares ........................ 25,788,571 29,979,397 35,364,363 Effect of dilutive securities: Stock options and warrants..................... - - 711,928 -------------------------------------------------------- Dilutive potential common shares Denominator for diluted earnings per share - adjusted weighted-average shares and assumed conversions..................................... 25,788,571 29,979,397 36,076,291 ======================================================== Basic earnings (loss) per share: Net income (loss) before cumulative effect of accounting change................................e $ (0.76) $ (3.95) $ 1.59 Cumulative effect of accounting change.......... - - (0.01) -------------------------------------------------------- F-25 Net income (loss) per common share................ $ (0.76) $ (3.95) $ 1.58 ======================================================== Diluted earnings (loss) per share: Net income (loss) before cumulative effect of accounting change................................e $ (0.76) $ (3.95) $ 1.56 Cumulative effect of accounting change.......... - - (0.01) -------------------------------------------------------- Net income (loss) per common share - diluted. $ (0.76) $ (3.95) $ 1.55 ========================================================
For the year ended December 31, 2001and 2002, 4.3 million shares and 5.9 million shares respectively, were excluded from the calculation of diluted earnings per share since their inclusion would have been anti-dilutive. 12 Quarterly Results of Operations (Unaudited) Selected results of operations for each of the fiscal quarters during the years ended December 31, 2002 and 2003 are as follows:
1st 2nd 3rd 4th Quarter Quarter Quarter Quarter ---------------- ---------------- --------------- ---------------- (In thousands, except per share data) Year Ended December 31, 2002 Net revenue........................... $ 11,807 $ 14,235 $ 11,061 $ 17,217 Operating income (loss)............... (735) (115,879) 490 5,221 Net income (loss)..................... (8,699) (95,690) (8,438) (5,700) Net income (loss) per common share - basic and diluted................... $ (0.29) $ (3.19) $ (0.28) $ (0.19) Year Ended December 31, 2003 Net revenue........................... $ 13,111 $ 8,430 $ 8,430 $ 9,048 Operating income (loss)............... 5,646 1,927 2,694 1,275 Net income (loss)..................... 62,702 (2,346) (2,702) (1,734) Net income (loss) per common share - basic............................... $ 1.83 $ (0.07) $ (0.08) $ (0.05) Net income (loss) per common share - diluted............................. $ 1.82 $ (0.07) $ (0.08) $ (0.05)
During the second quarter of 2002, the Company incurred a ceiling limitation write-down of approximately $116.0 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 2002 or 2003. 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 in 2002 and $12,000 in 2003. 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 Old Grey Wolf, as of December 31, 2002 and 2003 and the related consolidating statements of operations and cash flows for the years ended December 31, 2001, 2002 and 2003. Canadian Abraxas was 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). Old Grey Wolf was a non-guarantor with respect to the First Lien Notes and the Old Notes. The First Lien Notes and the Second Lien Notes were retired in connection with the financial restructuring transactions which occurred in January 2003. New Grey Wolf is a guarantor of the New Notes, there are no non-guarantor subsidiaries, accordingly, condensed consolidating balance sheets of Abraxas, as parent and its subsidiary New Grey Wolf are presented as of December 31, 2003 and the related consolidating statements of operations and cash flows for the year ended December 31, 2003. F-26
Condensed Consolidating Parent Company and Subsidiaries Balance Sheet December 31, 2003 (In thousands) Abraxas Abraxas Petroleum Reclassifi-cations Petroleum Corporation Subsidiary and Corporation and Inc. Parent (New Grey eliminations Subsidiaries Company(1) Wolf) ---------------------------------------------------------------- Assets: Cash .................................... $ - $ 493 $ - $ 493 Accounts receivable, less allowance for doubtful accounts...................... 14,101 903 (6,681) 8,323 Equipment inventory ..................... 782 - - 782 Other current assets .................... 418 154 - 572 ----------------------------------------------------------------- Total current assets.............. 15,301 1,550 (6,681) 10,170 Property and equipment - net................ 76,021 35,542 - 111,563 Deferred financing fees, net .............. 4,410 - - 4,410 Deferred income taxes and other assets ..... 27,551 - (27,257) 294 ----------------------------------------------------------------- Total assets ............................ $ 123,283 $ 37,092 $ (33,938) $ 126,437 ================================================================= Liabilities and Stockholders' deficit: Current liabilities: Accounts payable ............................. $ 7,075 $ 8,652 $ (6,681) $ 9,046 Accrued interest ............................. 2,340 - - 2,340 Other accrued expenses ....................... 1,228 - - 1,228 ----------------------------------------------------------------- Total current liabilities................... 10,643 8,652 (6,681) 12,614 Long-term debt .................................. 184,649 - - 184,649 Future site restoration ........................ 776 601 - 1,377 ----------------------------------------------------------------- 196,068 9,253 (6,681) 198,640 Stockholders' equity (deficit)................... (72,785) 27,839 (27,257) (72,203) ----------------------------------------------------------------- Total liabilities and stockholders' equity (deficit)........................................ $ 123,283 $ 37,092 $ (33,938) $ 126,437 =================================================================
(1) Includes amounts for insignificant U.S. subsidiaries, Sandia Oil and Gas, Sandia Operating, Western Energy Associates, East Side Coal and Wamsutter, which are guarantors of the New Notes.
Condensed Consolidating Parent Company, Restricted Subsidiaries and Non-Guarantor Balance Sheet December 31, 2002 (In thousands) Abraxas Non-Guarantor Abraxas Petroleum Restricted Subsidiary Reclassifi- Petroleum Corporation Subsidiary (Old Grey cations and Corporation and Inc. Parent (Canadian Wolf) eliminations Subsidiaries Company(2) Abraxas) ----------------------------------------------------------------------------- Assets: Current assets: Cash .................................... $ 557 $ 2,188 $ 2,137 $ - $ 4,882 Accounts receivable, less allowance for doubtful accounts...................... 4,482 4,782 11,938 (11,157) 10,045 Equipment inventory ..................... 860 142 12 - 1,014 Other current assets .................... 316 682 242 - 1,240 ----------------------------------------------------------------------------- Total current assets.............. 6,215 7,794 14,329 (11,157) 17,181 F-27 Property and equipment - net................ 74,435 38,858 37,101 - 150,394 Deferred financing fees, net .............. 2,970 688 2,013 - 5,671 Deferred income taxes and other assets ..... 108,558 7,820 (108,199) 8,179 ----------------------------------------------------------------------------- Total assets ............................ $ 192,178 $47,340 $61,263 $ (119,199) $181,425 ============================================================================= Liabilities and Stockholders' deficit: Current liabilities: Accounts payable ............................. $ 15,928 $ 766 $ 6,398 $ (10,973) $ 12,119 Accrued interest ............................. 5,000 1,009 - - 6,009 Other accrued expenses ....................... 1,162 - - - 1,162 Current maturities of long-term debt ......... 63,500 - - - 63,500 ----------------------------------------------------------------------------- Total current liabilities................... 85,590 1,775 6,398 (10,973) 82,790 Long-term debt .................................. 138,350 52,629 45,964 - 236,943 Future site restoration ........................ - 3,171 775 - 3,946 ----------------------------------------------------------------------------- 223,940 57,575 53,137 (10,973) 323,679 Stockholders' equity (deficit)................... (31,762) (10,235) 8,126 (108,383) (142,254) ----------------------------------------------------------------------------- Total liabilities and stockholders' equity (deficit)........................................ $ 192,178 $ 47,340 $ 61,263 $ (119,356) $ 181,425 =============================================================================
(2) Includes amounts for insignificant U.S. subsidiaries, Sandia Oil and Gas, Sandia Operating, Western Energy Associates, East Side Coal and Wamsutter, which are guarantors of the First and Second Lien Notes. Sandia is also a guarantor of the Old Notes. Additionally, these subsidiaries are designated as Restricted Subsidiaries along with Canadian Abraxas.
Condensed Consolidating Parent Company and Subsidiary Statement of Operations For the year ended December 31, 2003 (In thousands) Abraxas Abraxas Petroleum Reclassifi- Petroleum Corporation Subsidiary cation Corporation Inc. Parent (New Grey and and Company(1) Wolf) eliminations Subsidiaries ------------------------------ ------------------------------ Revenues: Oil and gas production revenues ............... $ 29,710 $ 8,395 $ - $ 38,105 Gas processing revenues........................ - 133 - 133 Rig revenues .................................. 663 - - 663 Other ........................................ 7 111 - 118 ------------------------------ ------------------------------ 30,380 8,639 - 39,019 Operating costs and expenses: Lease operating and production taxes .......... 8,342 1,257 - 9,599 Depreciation, depletion, and amortization ..... 7,608 3,195 - 10,803 Rig operations ................................ 609 - - 609 General and administrative .................... 3,995 1,365 - 5,360 Stock-based compensation....................... 1,106 - - 1,106 ------------------------------ ------------------------------ 21,660 5,817 - 27,477 ------------------------------ ------------------------------ Operating income (loss)........................... 8,720 2,822 - 11,542 Other (income) expense: Interest income ............................... (30) - - (30) Amortization of deferred financing fees........ 1,630 48 - 1,678 Interest expense............................... 16,323 632 - 16,955 Financing costs................................ 4,406 - - 4,406 Gain on sale of foreign subsidiaries........... (68,933) - - (68,933) Other ......................................... 100 674 - 774 ------------------------------ ----------------------------- (46,504) 1,354 - (45,150) ------------------------------ ------------------------------ Income (loss) before income tax and cumulative - effect of accounting change.................... 55,224 1,468 56,692 Income tax expense (benefit)...................... - 377 - 377 Cumulative effect of accounting change............ 395 - - 395 F-28 ------------------------------ ------------------------------ Net income (loss)................................ $ 54,829 $ 1,091 $ - $ 55,920 ============================== ==============================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the year ended December 31, 2002 (In thousands) Abraxas Petroleum Restricted Non-Guarantor Abraxas Corporation Subsidiary Subsidiary Reclassifi- Petroleum Inc. Parent (Canadian (Old Grey cations and Corporation and Company(2) Abraxas) Wolf) eliminations Subsidiaries ----------------------------------------------------------------------------- Revenues: Oil and gas production revenues ............... $ 20,835 $ 14,726 $ 15,301 $ - $ 50,862 Gas processing revenues........................ - 1,955 465 2,420 Rig revenues .................................. 635 - - - 635 Other ........................................ 71 152 180 - 403 --------------------------------------------------------------------------- 21,541 16,833 15,946 - 54,320 Operating costs and expenses: Lease operating and production taxes .......... 7,639 3,751 3,850 - 15,240 Depreciation, depletion, and amortization ..... 9,194 10,633 6,712 - 26,539 Proved property impairment .................... 28,178 60,501 27,314 - 115,993 Rig operations ................................ 567 - - - 567 General and administrative ................... 4,045 1,312 1,527 - 6,884 --------------------------------------------------------------------------- 49,623 76,197 39,403 - 165,223 --------------------------------------------------------------------------- Operating income (loss)........................... (28,082) (59,364) (23,457) - (110,903) Other (income) expense: Interest income ............................... (92) - - - (92) Amortization of deferred financing fees........ 1,325 366 404 - 2,095 Interest expense............................... 24,689 6,665 2,796 - 34,150 Other ......................................... 1,168 - - - 1,168 --------------------------------------------------------------------------- 27,090 7,031 3,200 - 37,321 --------------------------------------------------------------------------- Income (loss) before income tax .................. (55,172) (66,395) (26,657) - (148,224) Income tax expense (benefit)...................... - (18,522) (11,175) - (29,697) ------------------------------ -------------------------------------------- Net income (loss)................................ $ (55,172) $ (47,873 $ (15,482) $ - $ (118,527) ===========================================================================
Condensed Consolidating Parent Company, Restricted Subsidiary and Non-Guarantor Statement of Operations For the year ended December 31, 2001 (In thousands) Abraxas Petroleum Restricted Non-Guarantor Abraxas Corporation Subsidiary Subsidiary Reclassifi- Petroleum Inc. Parent (Canadian (Old Grey cations and Corporation and Company(2) Abraxas) 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 F-29 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) before income tax .................. (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) $ 1,642 $ - $ (19,718) ============================== ============================================
Condensed Consolidating Parent and Subsidiary Statement of Cash Flow For the year ended December 31, 2003 (In thousands) Abraxas Petroleum Reclassifi Abraxas Corporation Subsidiary -cations Petroleum Inc. Parent (New Grey and Corporation and Company(1) Wolf) eliminations Subsidiaries ---------------------------------------------------------------- Operating Activities Net income (loss) ........................... $ 54,829 $ 1,091 $ - $ 55,920 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Gain on sale of foreign subsidiaries.... (68,933) - - (68,933) Depreciation, depletion, and amortization ......................... 7,608 3,195 - 10,803 Non-cash interest and financing costs... 16,422 - - 16,422 Deferred income tax (benefit) expense... 377 - 377 Amortization of deferred financing fees. 1,630 48 - 1,678 Stock-based compensation................ 1,106 - - 1,106 Changes in operating assets and liabilities: Accounts receivable ................ (7,850) 394 6,010 (1,446) Equipment inventory ................ 78 - - 78 Other ............................. 295 - - 295 Accounts payables and accrued expenses ......................... 6,294 7,266 (6,010) 7,550 ----------------------------------------------------------------- Net cash provided by (used in)operations..... 11,479 12,371 - 23,850 Investing Activities Capital expenditures, including purchases and development of properties ............ (9,194) (9,155) - (18,349) Proceeds from sale of foreign subsidiaries... 85,810 - - 85,810 ----------------------------------------------------------------- Net cash provided (used) by investing activities................................ 76,616 (9,155) - 67,461 F-30 Financing Activities Proceeds from issuance of common stock....... 177 - - 177 Proceeds from long-term borrowings........... 43,051 291 - 43,342 Payments on long-term borrowings ............ (131,283) (7,261) - (138,544) Deferred financing fees...................... (597) - - (597) ----------------------------------------------------------------- Net cash provided (used) by financing activities................................ (88,652) (6,970) - (95,622) Effect of exchange rate changes on cash ..... - (78) - (78) ----------------------------------------------------------------- Increase (decrease) in cash ................. (557) (3,832) - (4,389) Cash at beginning of year ................... 557 4,325 - 4,882 ---------------------------------------------------------------- Cash at end of year.......................... $ - $ 493 $ - $ 493 =================================================================
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the year ended December 31, 2002 (In thousands) Abraxas Petroleum Restricted Non-Guarantor Abraxas Corporation Subsidiary Subsidiary Reclassifi- Petroleum Inc. Parent (Canadian (Old Grey cations and Corporation and Company(2) Abraxas) Wolf) eliminations Subsidiaries ----------------------------------------------------------------------------- Operating Activities Net income (loss) ........................... $ (55,172) $ (47,873) $ (15,482) $ - $ (118,527) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization ......................... 9,194 10,633 6,712 - 26,539 Proved property impairment ............. 28,178 60,501 27,314 - 115,993 Deferred income tax (benefit) expense... - (18,522) (11,175) - (29,697) Amortization of deferred financing fees. 1,325 366 404 - 2,095 Changes in operating assets and liabilities: Accounts receivable ................ 18,088 (3,187) 1,114 (18,262) (2,247) Equipment inventory ................ 201 - - - 201 Other ............................. 381 (177) (78) - 126 Accounts payables and accrued expenses ......................... (47) 479 (3,251) - (2,819) ------------------------------------------------------------------------------ Net cash provided by (used in)operations..... 2,148 2,220 5,555 (18,262) (8,336) Investing Activities Capital expenditures, including purchases and development of properties ............ (5,070) (4,926) (28,916) - (38,912) Proceeds from sale of oil and gas properties................................ 9,725 21,789 2,362 - 33,876 ------------------------------------------------------------------------------ Net cash provided (used) by investing activities................................ 4,655 16,863 (26,554) - (5,036) Financing Activities Proceeds from long-term borrowings........... - - 20,551 - 20,551 Payments on long-term borrowings ............ (8,176) (18,262) - 18,262 (8,176) Deferred financing fees...................... (1,663) 146 (22) - (1,539) ------------------------------------------------------------------------------ Net cash provided (used) by financing activities................................ (9,839) (18,116) 20,529 18,262 10,836 ------------------------------------------------------------------------------ Effect of exchange rate changes on cash ..... - (24) (163) - (187) ------------------------------------------------------------------------------ Increase (decrease) in cash ................. (3,036) 943 (630) - (2,723) Cash at beginning of year ................... 3,593 1,245 2,767 - 7,605 ------------------------------------------------------------------------------ Cash at end of year.......................... $ 557 $ 2,188 $ 2,137 $ - $ 4,882 ==============================================================================
F-31
Condensed Consolidating Parent, Restricted Subsidiary and Non-Guarantor Statement of Cash Flow For the year ended December 31, 2001 (In thousands) Abraxas Petroleum Restricted Non-Guarantor Abraxas Corporation Subsidiary Subsidiary Reclassifi- Petroleum Inc. Parent (Canadian (Old Grey cations and Corporation and Company(2) Abraxas) Wolf) eliminations Subsidiaries ----------------------------------------------------------------------------- Operating Activities Net income (loss) ........................... $ (14,848) $ (6,512) $ 1,642 $ - $ (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 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 ==============================================================================
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 in each country. The Company's F-32 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 2003, three customers accounted for approximately 67% of consolidated oil and natural gas production revenue. Three customers accounted for approximately 80% of United States revenue and three customer accounted for approximately 91% of revenue in Canada. In 2002, four customers accounted for approximately 79% of consolidated oil and natural gas production revenue. Three customers accounted for approximately 77% of United States revenue and one customer accounted for approximately 80% of revenue in Canada. In 2001, three customers accounted for approximately 41% of oil and natural gas production revenues. Three customers accounted for approximately 76% of United States revenue and five customers accounted for approximately 76% of revenue in Canada. 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 ........................... 4,560 ------------------- Total assets ............................ $ 303,616 =================== Business segment information about the Company's 2002 operations in different geographic areas is as follows: U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................... $ 21,541 $ 32,779 $ 54,320 ================== ================== =================== Operating loss.............................. $ (23,677) $ (82,821) $ (106,498) ================== ================== General corporate ............................................................... (4,405) Net interest expense and amortization of deferred financing fees ...................................................... (36,153) Other expense.................................................................... (1,168) ------------------- Loss before income taxes......................................................... $ (148,224) =================== Identifiable assets at December 31, 2002.... $ 81,025 $ 94,059 $ 175,084 ================== ================== Corporate assets ........................... 6,341 ------------------- Total assets ............................ $ 181,425 =================== Business segment information about the Company's 2003 operations in different geographic areas is as follows: U.S. Canada Total ------------------ ------------------ ------------------- (In thousands) Revenues ................................... $ 30,380 $ 8,639 $ 39,019 ================== ================== =================== Operating income............................ $ 14,001 $ 2,822 $ 16,823 ================== ================== F-33 General corporate ............................................................... (5,281) Net interest expense, financing cost and amortization of deferred financing fees ...................................... (23,009) Gain on sale of foreign subsidiaries............................................. 68,933 Other income (expense) - net..................................................... (774) Cumulative effect of accounting change........................................... (395) ------------------- Income before income taxes....................................................... $ 56,297 =================== Identifiable assets at December 31, 2003.... $ 84,228 $ 37,092 $ 121,320 ================== ================== Corporate assets ........................... 5,117 ------------------- Total assets ............................ $ 126,437 ===================
16. Hedging Program and Derivatives On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137 "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities. 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 Company has not elected hedge accounting for the floors that are in place as of December 31, 2003, accordingly, adjustments to the carrying value of the instruments are recognized in oil and gas income in the current period. Under the terms of the Company's senior credit agreement, the Company is required to maintain hedging agreements with respect to not less than 25% nor more than 75% of it crude oil and natural gas production for a rolling six month period. The credit agreement was amended in February 2004, see Note 2, increasing the minimum hedged position to 40% of our estimated production. As of December 31, 2003 the Company's hedging positions were as follows: Time Period Notional Quantities Price --------------------------------- ---------------------------- ---------------- March 1, 2003 - February 29, 5,000 MMBtu of natural gas Floor of $4.50 2004 production per day March 1, 2004 - April 30, 2004 2,000 MMBtu of natural gas Floor of $4.00 production per day March 1, 2004 - April 30, 2004 500 Bbl of crude oil Floor of $22.00 production per day May 2004 2,000 MMbtu of natural gas Floor of $4.00 production per day May 2004 500 Bbls of crude oil Floor of $22.00 production per day June 2004 800 Bbls of crude oil Floor of $22.00 production per day July 2004 2,000 MMbtu of natural gas Floor of $4.00 production per day July 2004 500 Bbl of crude oil Floor of $22.00 production per day 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 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 31, 2003, a commodity price increase of 10% would have resulted in an unfavorable change in the fair market value of approximately $2,000 and a commodity price decrease of 10% would have resulted in a favorable change in fair market value of approximately $2,000. F-34 17. 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. During the second quarter of 2002, the Company had a ceiling limitation write-down of approximately $116.0 million. At December 31, 2003, the net capitalized cost of crude oil and natural gas properties did not exceed the present value of our estimated reserves, as such, no write-down was recorded. F-35 18. 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 ----------------------------------------------------------------------------------------- 2002 2003 ----------------------------------------------------------------------------------------- Total U.S. Canada Total U.S. Canada ----------------------------------------------------------------------------------------- (In thousands) Proved crude oil and natural gas properties ............ $ 521,995 $ 279,401 $ 242,594 $ 325,222 $ 288,559 $ 36,663 Unproved properties ......... 7,052 - 7,052 4,304 - 4,304 ------------- ------------- --------------- -------------- -------------- ------------- Total........................... 529,047 279,401 249,646 329,526 288,559 40,967 Accumulated depreciation, depletion, and amortization, and impairment ................ (420,344) (205,181) (215,163) (219,404) (212,609) (6,795) -------------- -------------- ------------- ------------- -------------- ------------ Net capitalized costs ... $ 108,703 $ 74,220 $ 34,483 $ 110,122 $ 75,950 $ 34,172 ============= ============= =============== ============== ============== =============
Cost incurred in oil and gas property acquisitions, exploration and development activities are as follows:
Years Ended December 31 --------------------------------------------------------------------------------------------------- 2001 2002 2003 -------------------------------- -------------------------------- ---------------------------- Total U.S. Canada Total U.S. Canada (1) Total U.S. Canada --------- -------- -------- -------- --------- --------- --------- -------- ------ (In thousands) Property acquisition costs: Proved ................... $ - $ - $ - $ - $ - $ - $ - $ - $ - Unproved ................. - - - - - - - - - --------- -------- -------- -------- --------- --------- --------- -------- ------ $ - $ - $ - $ - $ - $ - $ - $ - $ - ========= ======== ======== ======== ========= ========= ========= ======== ====== Property development and exploration costs ........ $ 56,694 $ 18,867 $ 37,827 $ 38,560 $ 4,944 $ 33,616 $ 18,313 $ 9,158 $ 9,155 ========= ======== ======== ======== ========= ========= ========= ======== ======
(1) Canadian costs in 2002 were primarily for exploratory purposes. F-36 The results of operations for oil and gas producing activities for the three years ending December 31, 2001, 2002 and 2003, respectively are as follows:
Years Ended December 31 --------------------------------------------------------------------------------------------------- 2001 2002 2003 -------------------------------- -------------------------------- ---------------------------- Total U.S. Canada Total U.S. Canada (1) Total U.S. Canada --------- -------- -------- -------- --------- --------- --------- -------- ------ (In thousands) Revenues ................... $ 73,201 $ 34,934 $ 38,267 $ 50,862 $ 20,835 $ 30,027 $ 38,105 $ 29,710 $ 8,395 Production costs ........... (18,616) (9,302) (9,314) (15,240) (7,639) (7,601) (9,599) (8,342) (1,257) Depreciation, depletion, and amortization ......... (32,124) (11,976) (20,148) (26,224) (8,879) (17,345) (9,410) (7,428) (1,982) Proved property impairment . (2,638) - (2,638) (115,993) (28,178) (87,815) - - - General and administrative . (1,565) (1,073) (492) (1,836) (1,011) (825) (1,339) (998) (341) Income taxes (expense) benefit................... (2,419) - (2,419) - - - (377) - (377) --------- -------- --------- -------- --------- --------- --------- -------- ------ Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) ......... $ 15,839 $ 12,583 $ 3,256 $ (108,431) $(24,872) $ (83,559) $ 17,380 $ 12,942 $ 4,438 ========== ======== ========= ========== ========= =========- ========= ========= ======= Depletion rate per barrel of oil equivalent, before impact of impairment ..... $ 8.8 1 $ 6.96 $ 10.45 $ 8.52 $ 7.55 $ 8.94 $ 7.13 $ 7.24 $ 6.74 ========== ======== ========= ========== ========= =========- ========= ========= =======
F-37 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, 2001, 2002, and 2003. 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 January 1, 2001................... 8,844 191,327 6,081 114,908 2,763 76,419 Revisions of previous estimates ........... (628) 2,944 (688) 3,318 60 (374) Extensions and discoveries ................ 1,064 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 Revisions of previous estimates ........... (798) (29,701) (63) (15,248) (735) (14,453) Extensions and discoveries ................ 522 19,166 - - 522 19,166 Production ................................ (534) (15,453) (264) (5,472) (270) (9,981) Sale of minerals in place ................. (1,387) (23,937) (843) (9,553) (544) (14,384) ------------------------------------------------------------------------------ Balance at December 31, 2002 ................ 4,605 138,832 3,237 78,195 1,368 60,637 Revisions of previous estimates ........... 310 5,564 268 6,760 42 (1,196) Extensions and discoveries ................ 654 4,474 44 28 610 4,446 Production ................................ (288) (6,190) (229) (4,781) (59) (1,409) Sale of minerals in place ................. (1,146) (46,396) - - (1,146) (46,396) ------------------------------------------------------------------------------ Balance at December 31, 2003................. 4,135 96,284 3,320 80,202 815 16,082 ==============================================================================
F-38 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) Proved developed reserves: December 31, 2001 ........................... 5,047 111,243 2,892 40,514 2,155 70,729 ============================================================================== December 31, 2002............................ 3,004 90,374 1,754 34,776 1,250 55,598 ============================================================================== December 31, 2003............................ 2,314 52,398 1,887 39,371 427 13,027 ==============================================================================
F-39 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 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, 2003 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-40 Set forth below is the Standardized Measure relating to proved oil and gas reserves for the three years ending December 31, 2001, 2002 and 2003
Years Ended December 31 ---------------------------------------------------------------------------------------------------- 2001 2002 2003 ----------------------------------------------------------------------------------------------------- Total U.S. Canada Total U.S. Canada Total U.S. Canada ----------------------------------------------------------------------------------------------------- (In thousands) Future cash inflows ..... $ 607,375 $ 313,640 $ 293,735 $ 686,055 $ 389,061 $296,994 $ 621,290 $ 512,797 $108,493 Future production and development costs ..... (220,613) (138,296) (82,317) (225,068) (158,507) (66,561) (204,537) (179,036) (25,498) Future income tax expense - - - - - - - - - ------------------------------------------------------------------------------------------------------ Future net cash flows ... 386,762 175,344 211,418 460,987 230,554 230,433 416,756 333,761 82,995 Discount ................ (177,096) (98,157) (78,939) (206,134) (120,238) (85,896) (199,933) (172,177) (27,756) ------------------------------------------------------------------------------------------------------ Standardized Measure of discounted future net cash relating to proved reserves .............. $ 209,666 $ 77,187 $ 132,479 $ 254,853 $ 110,316 $144,537 $ 216,823 $ 161,584 $ 55,239 ======================================================================================================
F-41 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 ------------------------------------ 2001 2002 2003 --------- --------- --------- (In thousands) Standardized Measure, beginning of year ............................................ $ 775,534 $ 209,666 $ 254,853 Sales and transfers of oil and gas produced, net of production costs .................. (54,585) (35,622) (28,506) Net changes in prices and development and production costs from prior year ............... (613,325) 111,087 62,074 Extensions, discoveries, and improved recovery, less related costs ....................... 39,982 46,803 21,819 Sales of minerals in place ........................... (96,096) (33,808) (120,150) Revision of previous quantity estimates .............. (2,474) (36,007) 9,061 Change in future income tax expense .................. 230,987 -- -- Other ................................................ (147,910) (28,232) (7,813) Accretion of discount ................................ 77,553 20,966 25,485 --------- --------- --------- Standardized Measure, end of year .................. $ 209,666 $ 254,853 $ 216,823 ========= ========= =========
19. Restatement In January 2003, the Company sold its wholly owned Canadian subsidiaries, Old Grey Wolf and Canadian Abraxas as part of a series of transactions related to a financial restructuring - see Note 2 for additional information regarding an exchange offer, redemption of certain notes and a new credit agreement. Subsequent to the issuance of its consolidated financial statements for the year ended December 31, 2002, the Company's management determined that the wholly owned Canadian subsidiaries should not have been presented as discontinued operations. As a result, the accompanying consolidated balance sheets as of December 31, 2002, and the related consolidated statements of operations, and cash flows for each of the two years in the period ended December 31, 2002 have been restated to present the assets and liabilities, results of operations, and cash flows as components of continuing operations. A summary of the significant effects of the restatement is as follows (In thousands):
For the years ended December 31, -------------------------------------------------------------------- 2001 2002 ---------------------------------- --------------------------------- As Previously As Restated As Previously As Restated Reported Reported ------------------- -------------- ---------------- ---------------- Revenues: Oil and gas production revenue $ 34,934 $ 73,201 $ 21,601 $ 50,862 Gas processing revenue - 2,438 - 2,420 Rig revenue 756 756 635 635 Other 85 848 71 403 ------------- ------------ ------------- ------------- 35,775 77,243 22,307 54,320 Operating costs and expenses: Lease operating and production taxes 9,302 18,616 7,910 15,240 Depreciation, depletion and amortization 12,336 32,484 9,654 26,539 F-42 Proved property impairment - 2,638 32,850 115,993 Rig operations 702 702 567 567 General and administrative 4,937 6,445 5,082 6,884 General and administrative (Stock-based compensation) (2,767) (2,767) - - ------------- ------------ ------------- ------------- 24,510 58,118 56,063 165,223 ------------- ------------ ------------- ------------- Operating income (loss) 11,265 19,125 (33,756) (110,903) Other (income) expense: Interest income (78) (78) (92) (92) Amortization of deferred financing fees 1,907 2,268 1,325 2,095 Interest expense 23,922 31,523 24,689 34,150 Financing costs - - 967 967 (Gain) loss on sale of equity investment 845 845 - - Gain on debt extinguishment (1) - - - - Other 207 207 201 201 ------------- ------------ ------------- ------------- 26,803 34,765 27,090 37,321 ------------- ------------ ------------- ------------- Income (loss) before income tax (15,538) (15,640) (60,846) (148,224) Income tax expense (benefit): Current 505 505 - - Deferred - 1,897 - (29,697) Minority interest in income of consolidated foreign subsidiary - 1,676 - - Loss from discontinued operations (3,675) - (57,681) - ------------- ------------ ------------- ------------- Net income (loss) $ (19,718) $ (19,718) $ (118,527) $ (118,527) ============= ============ ============= =============
F-43
December 31, 2002 ---------------------------------- As Previously As Restated Reported ----------------- ------------ Current Assets: Cash $ 557 $ 4,882 Accounts receivable: Joint owners 516 2,215 Oil and gas production sales 5,292 7,466 Other 221 364 ----------------- ------------ 6,029 10,045 Equipment inventory 1,021 1,014 Other current assets 316 1,240 ----------------- ------------ 7,923 17,181 Assets held for sale 74,247 - ----------------- ------------ Total current assets 82,170 17,181 Property and equipment: Oil and gas properties: Proved 298,972 521,995 Unproved 7,052 7,052 Other property and equipment 2,713 44,189 ----------------- ------------ Total 308,737 573,236 Less accumulated depreciation, depletion and amortization 212,811 422,842 ----------------- ------------ Total property and equipment - net 95,926 150,394 Deferred financing fees 2,970 5,671 Deferred income taxes - 7,820 Other 359 359 ----------------- ------------ Total assets $ 181,425 $ 181,425 ================= ============ Current Liabilities: Accounts payable $ 4,171 $ 9,687 Joint interest oil and gas production payable 1,637 2,432 Accrued interest 5,000 6,009 Other accrued expenses 1,162 1,162 Hedge liability - - Current maturities of long-term debt 63,500 63,500 ----------------- ------------ 75,470 82,790 Liabilities related to assets held for sale 56,697 - ----------------- ------------ Total current liabilities 132,167 82,790 Long-term debt 190,979 236,943 Deferred income taxes - - Future site restoration 533 3,946 Stockholders' equity (deficit) (142,254) (142,254) ----------------- ------------ Total liabilities and stockholders' deficit $ 181,425 $ 181,425 ================= ============
F-44 FINANCIAL STATEMENTS GREY WOLF EXPLORATION INC. December 31, 2002 F-45 Deloitte & Touche LLP 3000, 700 Second Street SW Calgary AB Canada T2P 0S7 Telephone +1 403-267-1700 Facsimile +1 403-264-2871 AUDITORS' REPORT To the Directors of Grey Wolf Exploration Inc. We have audited the balance sheet of Grey Wolf Exploration Inc. as at December 31, 2002 and the statements of earnings (loss) and retained earnings (deficit) and of cash flows for each of the years in the two-year period ended December 31, 2002. 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, 2002, 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, 2002 and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles. Calgary, Canada /s/ Deloitte & Touche LLP March 10, 2003 Chartered Accountants F-46 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 recommendation section 3500. In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) outlining significant subsequent events that have been disclosed in the financial statements. We have not audited any financial statements of the Company for any period subsequent to December 31, 2002. However, as discussed in Note 13, the Company's parent company sold all of the outstanding common shares of the Company on January 23, 2003. Calgary, Canada /s/ Deloitte & Touche LLP March 10, 2003 Chartered Accountants F-47
GREY WOLF EXPLORATION INC. Balance Sheet As At December 31 (Thousands of Canadian dollars) 2002 $ ---------------------- ASSETS Current Cash 3,365 Accounts receivable (Note 10) 8,230 ---------------------- 11,595 Long-term receivable (Note 10) 10,000 Property and equipment (Note 3) 23,401 Future income taxes (Note 6) 25,233 ---------------------- 70,229 ---------------------- Liabilities Current Accounts payable and accrued liabilities (Note 10) 10,078 Long-term debt (Note 4) 69,227 Future site restoration and abandonment 1,221 Future income taxes (Note 6) - ---------------------- 80,526 ---------------------- CONTINGENCIES (Note 11) SHAREHOLDERS' EQUITY (DEFICIENCY) Share capital (Note 5) 27,891 Retained earnings (deficit) (38,188) ---------------------- (10,297) ---------------------- 70,229 ----------------------
See accompanying notes F-48
GREY WOLF EXPLORATION INC. Statements of Earnings (Loss) and Retained Earnings (Deficit) Years Ended December 31 (thousands of Canadian dollars, except for share amounts) 2002 2001 $ $ ----------------------------------- Revenue Petroleum and natural gas sales 33,245 30,268 Royalties, net of Alberta Royalty Tax Credit (8,237) (7,615) ----------------------------------- 25,008 22,653 ----------------------------------- Expenses Operating 6,032 3,844 General and administrative (Note 3) 2,367 1,278 Interest and finance charges (Note 10) 4,518 1,827 Depletion, depreciation and site restoration (Note 3) 8,003 8,364 Write down of petroleum and natural gas properties and facilities 82,635 - Amortization of deferred financing fees (Note 4) 634 - ----------------------------------- 104,189 15,313 ----------------------------------- Earnings (loss) before taxes (79,181) 7,340 ----------------------------------- Provision for (recovery of) taxes (Note 6) Current 24 144 Future (31,592) 3,061 ----------------------------------- (31,568) 3,205 ----------------------------------- Net earnings (loss) (47,613) 4,135 Retained earnings, beginning of year 9,425 5,290 ----------------------------------- Retained earnings (deficit), end of year (38,188) 9,425 ----------------------------------- Basic and diluted earnings (loss) per share (Note 7) (3.71) 0.32 ----------------------------------- Weighted average number of shares Basic 12,841,327 12,776,407 Diluted 12,841,327 12,776,407 -----------------------------------
See accompanying notes F-49
GREY WOLF EXPLORATION INC. Statements of Cash Flows Years Ended December 31 (Thousands of Canadian dollars, except for share amounts) 2002 2001 $ $ ------------------------------------- Operating Activities Net earnings (loss) (47,613) 4,135 Depletion, depreciation and site restoration 8,003 8,364 Write down of petroleum and natural gas properties and facilities 82,635 - Future income tax expense (recovery) (31,592) 3,061 Amortization of deferred financing fees 634 - ------------------------------------- Cash flow from operations 12,067 15,560 Changes in non-cash working capital items (Note 9) (3,355) (746) ------------------------------------- 8,712 14,814 ------------------------------------- Financing Activities Increase in long-term debt 67,994 28,334 Repayments of long-term debt (35,723) - Increase in long-term receivable - (10,000) Issuance of common shares - 336 ------------------------------------- 32,271 18,670 ------------------------------------- ------------------------------------- Total cash resources provided 40,983 33,484 ------------------------------------- Investing Activities Expenditures for property and equipment 45,558 36,800 Other acquisitions - 1,071 Dispositions of property and equipment (3,657) (8,838) Site restoration 122 46 ------------------------------------- 42,023 29,079 ------------------------------------- Increase (decrease) in cash (1,040) 4,405 Cash, beginning of year 4,405 - ------------------------------------- Cash, end of year 3,365 4,405 ------------------------------------- Basic and diluted cash flow from operations per share (Note 7) 0.94 1.22 ------------------------------------- Cash interest paid 5,483 1,840 Cash taxes paid 88 82 -------------------------------------
See accompanying notes F-50 GREY WOLF EXPLORATION INC. Notes to the Financial Statements Years Ended December 31, 2002 and 2001 ----------------------------------------------------------------------------- (Tabular amounts in thousands of Canadian 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, 2002 the Company was a wholly-owned subsidiary of Abraxas Petroleum Corporation ("Abraxas"). 2. SIGNIFICANT ACCOUNTING POLICIES These financial statements have been prepared in accordance with Canadian generally accepted accounting principles. Differences between Canadian and U.S. GAAP are outlined in Note 12 to the financial statements. Cash Cash includes amounts held in short-term deposits with original maturities of 90 days or less. Property and equipment 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 production facilities is calculated on a straight-line basis over an average 18-year term. F-51 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-52 2. SIGNIFICANT ACCOUNTING POLICIES (Continued) Petroleum and natural gas properties (Continued) The net carrying value of the Company's petroleum and natural gas properties is limited to an ultimate recoverable amount (the "ceiling test"). 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 period end prices and costs without escalation or discounting, and the income tax and Alberta Royalty Tax Credit legislation substantially enacted at the balance sheet date. 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. Future site restoration and abandonment costs The estimated cost of future 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. Use of estimates The amounts recorded for depletion and depreciation of property and equipment and the provision for site restoration are based on estimates of proved reserves and production rates. 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. F-53 2. SIGNIFICANT ACCOUNTING POLICIES (Continued) 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. Future income taxes The Company accounts for income taxes using the liability method. Under this method 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. Stock options Prior to December 31, 2001, the Company had a stock option plan as described in Note 5. No compensation expense was recognized when the stock options were issued. Consideration received on exercise of stock options was credited to share capital. Per share figures Basic per share figures are calculated using the weighted average number of common shares outstanding during the year. Effective January 1, 2001, the Company retroactively adopted, with restatement of prior periods, the new recommendations of CICA Handbook Section 3500. Under the revised standard, diluted per share figures are calculated based on 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. Prior to the adoption of the new recommendations, diluted per share amounts were determined using the imputed earnings method. F-54 2. SIGNIFICANT ACCOUNTING POLICIES (Continued) Comparative figures Certain of the prior years' comparative figures have been reclassified to conform to the current year's presentation. 3. PROPERTY AND EQUIPMENT
2002 -------------------------------------------------------- Accumulated Depletion and Net Book Cost Depreciation Value $ $ $ -------------------------------------------------------- Petroleum and natural gas properties 120,727 (102,708) 18,019 Gas plants and related production facilities 21,641 (16,314) 5,327 Other assets 621 (566) 55 -------------------------------------------------------- Net property and equipment 142,989 (119,588) 23,401 --------------------------------------------------------
For the year ended December 31, 2002, $701,000 of general and administrative expenses were capitalized as part of property and equipment related directly to the Company's exploration and development activities (2001 - $402,000). As a result of the quarterly ceiling test calculation at June 30, 2002, the Company recorded a write-down of its petroleum and natural gas properties and facilities in the amount of $82,635,000 ($49,649,000 net of related tax recovery). The impairment was primarily due to lower gas prices and reserve revisions subsequent to December 31, 2001, and higher future estimated interest costs relating to the Mirant Facility (Note 4). F-55 3. PROPERTY AND EQUIPMENT (Continued) Undeveloped property costs of $4,961,511 were excluded from the depletion base for the year ended December 31, 2002 (2001 - $6,065,907). Future site restoration and abandonment charges of $294,029 are included in depletion, depreciation and site restoration expense for the year ended December 31, 2002 (2001 - $197,987). 4. LONG-TERM DEBT Long term debt is comprised of the following: 2002 $ -------------------- Mirant Facility 72,398 Unamortized deferred financing charges (3,171) -------------------- 69,227 -------------------- At December 31, 2002, 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, 2002, $72,398,000 was drawn on this facility. Of the $72,398,000 drawn, $10,000,000 was advanced to Canaxas (Note 10). 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. Loan advances are supported by a first charge demand debenture in the amount of $200,000,000 together with a debenture pledge agreement providing a first priority lien on all the assets of the Company. Under the Mirant Facility, loan advances bear interest at 9.5%, plus a 5% overriding royalty which will decrease to 2.5% when certain conditions are met. The overriding royalty granted to Mirant was treated as a disposition of petroleum and natural gas properties in the amount of $3,600,000, with a corresponding deferred financing charge recorded of $3,600,000, based on the fair value at the date of disposition. This deferred charge plus additional fees paid in 2001 and 2002 to secure the facility have been netted against the outstanding loan balance and are being amortized over a 6-year period ending in 2007. F-57 4. LONG-TERM DEBT (Continued) At January 1, 2001, the Company had a revolving term credit facility with a Canadian chartered bank with a maximum limit of $20,000,000. Under the facility, loan advances bore interest at bank prime plus 1/8%, or 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 until replaced by the Mirant Facility in December 2001. Effective January 1, 2002, the Emerging Issues Committee of the CICA issued Abstract No. 122, which requires callable debt obligations to be presented with current liabilities on the balance sheet. The maximum available amount under the Mirant Facility may be terminated or reduced below the outstanding amount only upon certain unanticipated events of default, and therefore is not classified as a callable debt obligation. In addition, 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 a long-term liability on the balance sheet. The facility matures in December 2007. Interest and financing charges for the year ended December 31, 2002 includes $5,483,000 of interest expense relating to long-term debt (2001 - $843,000). F-58 5. SHARE CAPITAL Authorized Unlimited number of common shares without nominal or par value. Issued
Number of Amount Shares $ --------------------------------------------- --------------------------------------------- Balance, December 31, 2000 12,661,541 27,555 Exercise of stock options 179,786 336 --------------------------------------------- Balance, December 31, 2001 and 2002 12,841,327 27,891 ---------------------------------------------
Stock options Prior to December 31, 2001, a maximum of 1,270,000 options to purchase common shares were 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 the grant date and expiring in 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, 2000 1,010,029 2.30 Exercised (179,786) 1.87 Cancelled (830,243) 2.39 ------------------------ Balance, December 31, 2001 and 2002 - ------------------------
F-59 6. PROVISION FOR TAXES The total provision for taxes recorded differs from the tax calculated by applying the combined statutory Canadian corporate and provincial income tax rates as follows:
2002 2001 $ $ ------------------------------------- Calculated income tax (recovery) expense at 42.12% (2001 - 42.62%) (33,351) 3,128 Increase (decrease) in tax resulting from: Non-deductible crown royalties and other charges 2,511 2,950 Resource allowance and related items (583) (2,757) Alberta Royalty Tax Credit (105) (177) Large Corporation Tax 24 144 Tax rate adjustment (62) (151) Other (2) 68 ------------------------------------- Provision for (recovery of) taxes (31,568) 3,205 -------------------------------------
The major components of future income tax asset (liability) at December 31, 2002 is as follows: 2002 $ ------------------ Property and equipment 25,522 Future site restoration 514 Share issue costs 19 Attributed royalty income carried forward 607 Resource allowance (1,357) Deferred financing costs (72) ------------------ 25,233 ------------------ No valuation allowance has been recorded with respect to the future income tax asset balance at December 31, 2002 based on management's assessment that the amount is more likely than not to be realized. F-60 7. PER SHARE figures The treasury method of calculating per share figures was adopted retroactively effective January 1, 2001. There was no impact on 2001 diluted per share figures as a result of adopting the new treasury method. 8. 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, 2002, there were no significant differences between the carrying amounts of these financial instruments reported on the balance sheets and their estimated fair values. Credit risk The majority of the Company's accounts receivable are in respect of oil and gas operations. The Company generally extends unsecured credit to these customers, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not previously experienced any material credit loss in the collection of receivables. Interest rate risk The Company's long-term debt bears interest at a floating market rate plus 1/8%. Accordingly, the Company is subject to interest rate risk, as the required cash flow to service the debt will fluctuate as a result of changes in market rates. Commodity price risk The nature of the Company's operations results in exposure to fluctuations in commodity prices. The Company 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. The Company had not entered into any contracts as at December 31, 2002. F-61 9. SUPPLEMENTARY CASH FLOW INFORMATION
2002 2001 $ $ ------------------------------------- Accounts receivable 1,750 (165) Accounts payable and accrued liabilities (5,105) (581) ------------------------------------- Changes in non-cash working capital items (3,355) (746) -------------------------------------
10. 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, 2002, 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. During the year ended December 31, 2002, $2,967,200 was charged to Canaxas with respect to the Management Agreement (2001 - $2,633,716). Abraxas also charged the Company a corporate service charge of $885,000 for the year ended December 31, 2002 of which $480,000 was charged out to Canaxas. For the year ended December 31, 2001, the Abraxas corporate service charge was $849,000 of which $589,000 was charged out to Canaxas. All amounts relating to the Abraxas corporate service charge and the Management Agreement with Canaxas are non-interest bearing, are not collateralized and are due on demand. At December 31, 2002 the Company had a long-term receivable from Canaxas in the amount of $10,000,000 (Note 4). The balance bears interest at 9.65% and has no fixed terms of repayment. Interest and financing charges of $4,518,000 for the year ended December 31, 2002 are net of $965,000 (2001 - $Nil)interest income accrued related to the long-term receivable from Canaxas. Following is a summary of amounts included in accounts receivable and long-term receivable that are due from related parties as at December 31, 2002: F-62 10. RELATED PARTY TRANSACTIONS (Continued) 2002 $ ---------------------- Short-term receivable from Canaxas 1,236 Long-term receivable from Canaxas 10,000 11. contingencies The Company is subject to various claims arising from its operations in the normal course of business, none of which are expected, individually or in the aggregate, to have a material adverse impact on the Company's operations or financial position. 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES Reconciliation 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 (loss) and retained earnings (deficit) and of cash flows are described and quantified below for the years indicated: (a)Under 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 $168,000 in 2002 and $119,000 in 2001 with a corresponding decrease in interest expense in the respective periods. The cumulative decrease in interest expense under U.S. GAAP for years prior to 2001 was $69,000. F-63 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATESc GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) (b)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 financing 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. (c)Under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities at the balance sheet date, net of deferred income taxes and accumulated site restoration and abandonment liability, is limited to the present value of after-tax future net revenue from proven reserves, discounted at 10 percent, plus the lower of cost and fair value of unproved oil and gas properties. Under Canadian GAAP, the "ceiling test" calculation is performed using undiscounted after-tax net revenues, less future estimated general and administrative and financing costs plus the lower of cost and fair value of unproved oil and gas properties. Had the ceiling test been applied in accordance with U.S. GAAP, the write-down recorded for the year ended December 31, 2002 would have been lower by $41,155,000 ($25,464,000 after-tax). There were no differences between the application of the Canadian and U.S. GAAP ceiling tests in 2001, or for years prior to 2001. F-64 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) (d)Prior to 2000, Canadian GAAP required the use of the deferral method of accounting for income taxes. For fiscal periods beginning on or after January 1, 2000, retroactive adoption of the liability method of accounting for income taxes was required, which is substantially the same as Financial Accounting Standards Board Statement No. 109 under U.S. GAAP. However, upon adoption of the new recommendation for Canadian GAAP, companies were permitted to record the impact of differences in accounting and tax bases to retained earnings as a one-time transition adjustment. Accordingly, property and equipment would have been higher under U.S. GAAP by $682,000 for 2002 and 2001 before the impact of depletion. In addition, future income tax expense of $480,000 would have been recorded for 1999 under U.S. GAAP. (e)As a result of the Canadian - U.S. GAAP differences in capitalization of interest, "push down accounting", ceiling test write-down and adoption of the deferral method of accounting for incomes taxes as outlined in (a), (b), (c) and (d), respectively, depletion and depreciation expense and property and equipment under U.S. GAAP have been adjusted for each of the years ended December 31, 2002 and 2001. The cumulative increase in depletion and depreciation expense for years prior to 2001 was $246,000. (f)Future income taxes have been adjusted for the year ended December 31, 2002 for the tax impact of the Canadian - U.S. GAAP differences outlined in (a) through (e). Except for the impact on future tax expense for 1999 as noted in (d), the cumulative impact on future income taxes for years prior to 2002 was not significant. (g)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 Financial Accounting Standards Board Statement No. 128 under U.S. GAAP. Accordingly, no adjustments are required to conform the diluted earnings (loss) per share figures to U.S. GAAP, except for the net income (loss) effect of the above-noted Canadian - U.S. GAAP differences identified. F-65 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLYACCEPTED ACCOUNTING PRINCIPLES (Continued) The application of U.S. GAAP would have the following effect on the Statements of Earnings (Loss):
Years Ended December 31, ----------------- ----------------- 2002 2001 $ $ ----------------- ----------------- Net earnings (loss), as reported (47,613) 4,135 Capitalized interest (a) 168 119 Depreciation, depletion and site restoration (e) (2,401) (62) Write-down of petroleum and natural gas properties and facilities (c) 41,155 - Interest and financing charges (b) - 984 Future income tax expense (recovery) (f) (14,495) - ----------------- ----------------- Net earnings (loss), U.S. GAAP (23,186) 5,176 ----------------- ----------------- Basic and diluted earnings (loss) per share, as reported (3.71) 0.32 Effect of increase (decrease) in net earnings (loss) under U.S. GAAP 1.90 0.09 ----------------- ----------------- Basic and diluted earnings (loss) per share, U.S. GAAP (g) (1.81) 0.41 ----------------- -----------------
F-66 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) The application of U.S. GAAP would have the following effect on the Balance Sheets:
As At December 31, 2002 -------------------------------------------- Cumulative As Increase U.S. Reported (Decrease) GAAP -------------- ---------------- ------------ ASSETS Accounts receivable (b) 8,230 984 9,214 Property and equipment (a)(b)(c)(d)(e) 23,401 35,414 58,815 Future income taxes (f) 25,233 (12,759) 12,474 LIABILITIES Future income taxes (d)(f) - - - SHAREHOLDERS' EQUITY (DEFICIENCY) Revaluation adjustment (b) - (2,338) (2,338) Retained earnings (deficit) (a)(b)(c)(d)(e)(f) (38,188) 25,977 (15,255)
F-67 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) The application of U.S. GAAP would have the following effect on the Statements of Cash Flows:
Years Ended December 31, ------------- -------------- 2002 2001 $ $ ------------- -------------- OPERATING ACTIVITIES Cash flow from operating activities, as reported 8,712 14,814 Increase (decrease) in: Net earnings (loss) 24,427 1,041 Depletion, depreciation and site restoration (e) 2,401 62 Write-down of petroleum and natural gas properties and facilities (c) (41,155) - Future income tax expense (recovery) (f) 14,495 - Changes in non-cash working capital items (b) - (984) ------------- -------------- Cash flow from operating activities, U.S. GAAP 8,880 14,933 ------------- -------------- INVESTING ACTIVITIES Net cash (used) provided by investing activities, as reported (42,023) (29,079) Increase in capital expenditures (a) (168) (119) ------------- -------------- Net cash (used) provided by investing activities, U.S. GAAP (42,191) (29,198) ------------- --------------
F-68 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) Under Canadian GAAP, companies 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 companies. 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 U.S. Accounting Developments Statement No. 143, "Accounting for Asset Retirement Obligations" (FAS 143) was released by the Financial Accounting Standards Board in June 2001. FAS 143 requires liability recognition for retirement obligations associated with tangible long-lived assets. The initial amount of the asset retirement obligation is to be recorded 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 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, in conjunction with the January 23, 2003 transaction as described in Note 13. The Financial Accounting Standards Board also recently issued Statement No. 144, "Accounting for the Impairment of Disposal of Long-Lived Assets" (FAS 144). FAS 144 will replace previous United States generally accepted accounting principles regarding accounting for impairment of long-lived assets and accounting and reporting for discontinued operations. FAS 144 retains the fundamental provisions of the prior standard for recognizing and measuring impairment losses on long-lived assets. FAS 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 144 for fiscal years beginning after December 15, 2001. The Company has adopted the accounting standard effective January 1, 2002. The standard is not expected to have a significant future impact on the Company's financial position and results of operations. F-69 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (Continued) The Financial Accounting Standards Board also recently issued Statement No. 146, "Accounting for Costs Associated With Exit or Disposal Activities" (FAS 146). FAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The standard is not expected to have a significant impact on the Company's financial position or results of operations. 13. SUBSEQUENT EVENTS On January 23, 2003, Abraxas completed the sale of all of the outstanding common shares of the Company to an unrelated third party (the "Purchaser") for gross cash proceeds of approximately $110,790,000, subject to closing adjustments. Upon closing of the sale, the Company was required to repay the outstanding indebtedness including accrued interest under the Mirant Facility, totaling $72,847,000. Prior to the sale, certain petroleum and natural gas assets of the Company with a net book value of $8,871,000 were transferred to a related newly-formed subsidiary of Abraxas, a portion of which will be developed jointly under farmout arrangements with the Purchaser. F-70