10-K 1 apb10k2004.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, 2004 [ ]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 non-affiliates of the registrant as of June 30, 2004, based upon the closing per share price of $1.66 was approximately $53,719,000 on such date. The number of shares of the registrant's common stock, par value $0.01 per share, outstanding as of March 18, 2005 was 36,813,758 shares of which 32,715,439 shares were held by non-affiliates. 1 Documents Incorporated by Reference: Portions of the registrant's Proxy Statement relating to the 2005 Annual Meeting of Shareholders to be held on June 1, 2005 have been incorporated by reference herein (Part III). 2
ABRAXAS PETROLEUM CORPORATION FORM 10-K TABLE OF CONTENTS PART I Page Item 1. Business.......................................................................................5 General.......................................................................................6 Markets and Customers.........................................................................7 Risk Factors..................................................................................8 Regulation of Natural Gas and Crude Oil Activities..........................................14 Environmental Matters ......................................................................16 Title to Properties..........................................................................17 Employees....................................................................................17 Item 2. Properties....................................................................................18 Primary Operating Areas......................................................................18 Exploratory and Developmental Acreage........................................................18 Productive Wells.............................................................................19 Reserves Information.........................................................................19 Crude Oil, Natural Gas Liquids and Natural Gas Production and Sales Prices ..................21 Drilling Activities..........................................................................21 Office Facilities............................................................................22 Other Properties.............................................................................22 Item 3. Legal Proceedings............................................................................23 Item 4. Submission of Matters to a Vote of Security Holders..........................................23 Item 4A. Executive Officers of Abraxas................................................................23 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities...............................................................24 Market Information...........................................................................24 Holders......................................................................................24 Dividends....................................................................................24 Recent Sales of Unregistered Securities......................................................24 Item 6. Selected Financial Data......................................................................25 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........26 General......................................................................................26 Results of Operations........................................................................28 Liquidity and Capital Resources..............................................................32 Critical Accounting Policies.................................................................41 New Accounting Pronouncements................................................................43 Item 7A. Quantitative and Qualitative Disclosures about Market Risk...................................43 Item 8. Financial Statements and Supplementary Data..................................................44 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......................................................44 3 Item 9A. Controls and Procedures.....................................................................45 Item 9B. Other Information............................................................................45 PART III Item 10. Directors and Executive Officers of the Registrant .........................................45 Item 11. Executive Compensation.......................................................................45 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.................................................................45 Item 13. Certain Relationships and Related Transactions...............................................45 Item 14. Principal Accounting Fees and Services .....................................................46 PART IV Item 15. Exhibits, Financial Statement Schedules......................................................46 SIGNATURES..................................................................................50
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 statements including words like "believe", "expect", "anticipate", "intend", "plan", "seek", "estimate", "could", "potentially" or similar expressions), you must remember that these are forward looking statements, and 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 "Summary" "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 success in development, exploitation and exploration activities; o our ability to make planned capital expenditures; o declines in our production of natural gas and crude oil; o prices for natural gas and crude oil; o our ability to raise equity capital or incur additional indebtedness; o political and economic conditions in oil producing countries, especially those in the Middle East; o prices and availability of alternative fuels; o our restrictive debt covenants; o our acquisition and divestiture activities; o results of our hedging activities; and o other factors discussed elsewhere in this report. PART I Item 1. Business As part of a series of restructuring transactions approved in 2004, we adopted a plan to dispose of our operations and interest in Grey Wolf Exploration Inc.("Grey Wolf"), a wholly-owned Canadian subsidiary of Abraxas Petroleum Corporation. In February 2005 Grey Wolf closed on an initial public offering ("IPO") resulting in our substantial divestiture of our capital stock in Grey Wolf. As a result of the disposal of Grey Wolf the results of operations of Grey Wolf are reflected in our Financial Statements and in this document as "Discontinued Operations" and our remaining operations are referred to in our Financial Statements and in this document as "Continuing Operations" or "Continued Operations". Unless otherwise noted, all disclosures are for continuing operations. See Notes 2 and 3 to the financial statements in Item 8. 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 5 natural gas liquids and MBbls is used to designate one thousand barrels of crude oil or natural gas liquids. General We are an independent energy company primarily engaged in the development and production of natural gas and crude oil. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a substantial inventory of low risk development opportunities, which provide a basis for significant production and reserve increases. In addition, we intend to expand upon our exploitation and development activities with complementary low risk exploration projects in our core areas of operation. Our core areas of operation are in south and west Texas and east central Wyoming. Our current producing properties are typically characterized by long-lived reserves, established production profiles and an emphasis on natural gas At December 31, 2004, we owned interests in 93,341 gross acres (81,748 net acres) applicable to our continuing operations, and operated properties accounting for approximately 95% of our PV-10, affording us substantial control over the timing and incurrence of operating and capital expenditures. At December 31, 2004 estimated total proved reserves were 93.7 Bcfe with an aggregate PV-10 of $149.0 million. We participated in the drilling of 4 gross (4 net) wells with 3 gross (3 net) wells being successful. We invested $9.3 million in capital spending on these activities during 2004. We believe that our high quality asset base, high degree of operational control and large inventory of drilling projects positions us for future growth. Our properties are concentrated in locations that facilitate substantial economies of scale in drilling and production operations and efficient reservoir management practices. In addition, we have 47 proved undeveloped locations and have identified over 100 drilling and recompletion opportunities on our existing acreage, the successful development of which we believe could significantly increase our daily production and proved reserves. In January 2003, we completed a series of transactions, which we sometimes refer to as the January 2003 financial restructuring, including the sale of most of our Canadian producing properties and the issuance by Abraxas of 11 1/2% secured notes due 2007. The terms of those notes limited our ability to make capital expenditures exceeding $10 million per year, which caused us to put a priority on those projects which allowed us to maintain our leasehold positions and comply with drilling requirements on non-operated properties, rather than on those opportunities which we believed had the greatest potential for increasing our production and reserves. On October 28, 2004, in order to provide us with greater flexibility in conducting our business, including increasing capital spending and exploiting our additional drilling opportunities, we refinanced all of our then existing indebtedness by redeeming our 11 1/2% secured notes due 2007 and terminating our previous credit facility with the net proceeds from: o the private issuance of $125.0 million aggregate principal amount of the Floating Rate Senior Secured Notes due 2009, Series A; o the proceeds of our $25.0 million second lien increasing rate bridge loan; and o the payment to us by Grey Wolf of $35.0 million from the proceeds of Grey Wolf's $35.0 million term loan. Interest on the bridge loan currently accrues at a rate of 12% per annum until October 28, 2005, and will be payable monthly in cash. Interest on the Bridge Loan will thereafter accrue at a rate of 15% per annum, and will be payable in-kind. Subject to earlier termination rights and events of default, the bridge loan's stated maturity date is October 28, 2010. We originally borrowed the full $25 million under the bridge loan, but paid down the bridge loan to approximately $5.4 million in February 2005 with the proceeds from the sale of secondary shares offered by us in connection with the Grey Wolf IPO, described below. 6 Until the Grey Wolf term loan was re-paid in full with the proceeds of the Grey Wolf IPO completed in February 2005, as described below, interest on the term loan accrued at the prime rate announced by the term loan's administrative agent plus 6.25%. Such interest was payable quarterly in cash with the first interest payment having been made on January 1, 2005. Subject to earlier termination rights and events of default, the Grey Wolf term loan would have matured on October 29, 2009. As a part of the October 2004 refinancing, we also entered into a new $15.0 million senior secured revolving credit facility, under which we currently have availability of approximately $13.0 million. Our new credit facility has a maximum commitment of $15 million, which includes a $2.5 million subfacility for letters of credit. Availability under the new credit facility is subject to a borrowing base consistent with normal and customary natural gas and crude oil lending transactions. Outstanding amounts under the new credit facility bear interest at the prime rate announced by Wells Fargo Bank, National Association plus 1.00%. Subject to earlier termination rights and events of default, the new credit facility's stated maturity date is October 28, 2008. In February 2005, we completed an exchange offer pursuant to which all the Floating Rate Senior Secured Notes due 2009, Series A were exchanged for Floating Rate Senior Secured Notes due 2009, Series B. These new notes continue to accrue interest from the date of issuance at a per annum floating rate of 6-month LIBOR plus 7.50%. The initial interest rate on these new notes is 9.72% per annum. The interest rate will reset semi-annually on each June 1 and December 1, commencing on June 1, 2005. Interest is payable in cash semi-annually in arrears on June 1 and December 1 of each year, commencing on June 1, 2005. Also as part of the restructuring plan in 2004 we approved a plan to dispose of our operations and interest in Grey Wolf. In February 2005, Grey Wolf closed on an initial public offering ("IPO") resulting in our substantial divestiture of our capital stock in Grey Wolf. Net proceeds of approximately $37 million from the offering by Grey Wolf of treasury shares were used to repay Grey Wolf's term loan in its entirety and eliminate its working capital deficit. Net proceeds of approximately $20 million from the secondary share offered by Abraxas were used to reduce the amount outstanding under its bridge loan to approximately $5.4 million. On March 24, 2005, we were advised of the underwriter's intent to exercise 3.5 million of the over allotment shares. Closing for this exercise is scheduled for March 31,2005 and will provide approximately $7.5 million that Abraxas will utilize to payoff the remaining balance of its Bridge Loan. The remaining proceeds of approximately $2 million will be used to pay down our revolving credit facility to, effectively, zero. Markets and Customers The revenue generated by our operations is highly dependent upon the prices of, and demand for, natural gas and crude oil. Historically, the markets for natural gas and crude oil have been volatile and are likely to continue to be volatile in the future. The prices we receive for our natural gas and crude oil production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation and policies. Decreases in the prices of natural gas and crude oil 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 - Risks Relating to Our Industry -- Market conditions for natural gas and crude oil and particularly volatility of prices for natural gas and crude oil could adversely affect our revenues, cash flows, profitability and Growth" and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies" for more information relating to the effects of decreases in natural gas and crude oil prices on us. Substantially all of our natural gas and crude oil is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2004 two purchasers accounted for approximately 64% of our natural gas and crude oil sales. We believe that there 7 are numerous other companies available to purchase our natural gas and crude oil and that the loss of one or more of these purchasers would not materially affect our ability to sell natural gas and crude oil. Risk Factors Risks Related to Our Business We have a highly leveraged capital structure, which limits our operating and financial flexibility. We have a highly leveraged capital structure. We currently have total indebtedness, including the notes, of approximately $126 million, all of which is secured indebtedness. Our highly leveraged capital structure will have several important effects on our future operations, including: o A substantial amount of our cash flow from operations will be required to service our indebtedness (including cash interest payments on the notes), which will reduce the funds that would otherwise be available for operations, capital expenditures and expansion opportunities, including developing our properties; o The covenants contained in our new revolving credit facility and bridge loan require us to meet certain financial tests and comply with certain other restrictions, including limitations on capital expenditures. These restrictions, together with those in the indenture governing the new notes, may limit our ability to undertake certain activities and respond to changes in our business and our industry; o Our debt level may impair our ability to obtain additional capital, through equity offerings or debt financings, for working capital, capital expenditures, or refinancing of indebtdness; o Our debt level makes us more vulnerable to economic downturns and adverse developments in our industry (especially declines in natural gas and crude oil prices) and the economy in general; and o The notes and the new revolving credit facility are subject to variable interest rates which makes us vulnerable to interest rate increases. We may not be able to fund the substantial capital expenditures that will be required for us to increase our reserves and our production. We are required to make substantial capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capital expenditures primarily with cash flow from operations, borrowings under credit facilities and sales of producing properties, and we expect to continue to do so in the future; however, we cannot assure you that we will have sufficient capital resources in the future to finance our capital expenditures. Volatility in natural gas and crude oil prices, the timing of our drilling program and our drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of our planned capital expenditures, a greater percentage of our cash flow from operations will be required for debt service (including cash interest payments on the notes) and our planned capital expenditures would, by necessity, be decreased. The borrowing base under the new revolving credit facility will be determined from time to time by our lenders , consistent with their customary natural gas and crude oil lending practices. Reductions in estimates of our natural gas and crude oil reserves could result in a reduction in our borrowing base, which would reduce the amount of financial resources available under the new revolving credit facility to meet our capital requirements. Such a reduction 8 could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lenders' inability to agree to an adequate borrowing base or adverse changes in the lenders' practices regarding estimation of reserves. If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploitation and development activities could be adversely affected. As a result, our ability to replace production may be limited. In addition, if the borrowing base under our new revolving credit facility is reduced, we would be required to reduce our borrowings under the new revolving credit facility so that such borrowings do not exceed the borrowing base. This could further reduce the cash available to us for capital spending and, if we did not have sufficient capital to reduce our borrowing level, could cause us to default under the new revolving credit facility, the notes and the bridge loan. We have sold producing properties to provide us with liquidity and capital resources in the past and may do so in the future. After any such sale, we would expect to utilize the proceeds to drill new wells. If we cannot replace the production lost from properties sold with production from new properties, our cash flow from operations will likely decrease which, in turn, would decrease the amount of cash available for debt service and additional capital spending. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition would be adversely affected. Our future natural gas and crude oil production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our natural gas and crude oil properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploitation activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration, exploitation and development activities will result in increases in our proved 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. As our proved reserves, and consequently our production, decline, our cash flow from operations and the amount that we are able to borrow under the new revolving credit facility will also decline. In addition, approximately 49% of our total estimated proved reserves at December 31, 2004 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Prior to the January 2003 financial restructuring, we implemented a number of measures to conserve our cash resources, including postponement of drilling projects. While these measures helped conserve our cash resources, they also limited our ability to replenish our depleting reserves. While the 11 1/2% secured notes due 2007 were outstanding, we also postponed drilling projects as a result of the capital spending limitations that existed in those notes. As a result, our current producing properties have continued to deplete, and we have not been able to drill new wells at a rate that we would have desired in the absence of these limitations. The terms of the new revolving credit facility and the bridge loan place limits on our capital expenditures, which could limit our ability to replenish our reserves and increase production. Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests. The new revolving credit facility, bridge loan and the indenture governing the notes contain a number of significant covenants that, among other things, limit our ability to: o Incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock; o transfer or sell assets; o create liens on assets; 9 o pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions; o engage in transactions with affiliates; o guarantee other indebtedness; o make any change in the principal nature of our business; o prepay, redeem, purchase or otherwise acquire any of our or our restricted subsidiaries' indebtedness; o permit a change of control; o directly or indirectly make or acquire any investment; o cause a restricted subsidiary to issue or sell our capital stock; and o consolidate, merge or transfer all or substantially all of the consolidated assets of Abraxas and our restricted subsidiaries. In addition, the new revolving credit facility and bridge loan require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary or desirable corporate activities. A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under the new revolving credit facility and bridge loan and the notes. A default, if not cured or waived, could result in all of our indebtedness, including the notes, becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Long-Term Indebtedness." 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 and transportation 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 regulation of natural gas and crude oil 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 natural gas and crude oil. Hedging transactions have in the past and may in the future impact our cash flow from operations. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and crude oil prices and to achieve more predictable cash flow. In 2002 and 2003, we experienced hedging costs of $1.5 million and $842,000, respectively; resulting from the price ceilings we established being exceeded by the index prices. For the year ended December 31, 2004 we recognized a gain from hedging activities of approximately $118,000. Currently, we believe our hedging arrangements, which are in the form of price 10 floors, do not expose us to significant financial risk. Although our hedging activities may limit our exposure to declines in natural gas and crude oil prices, such activities may also limit and have in the past limited, additional revenues from increases in natural gas and crude oil prices. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from financial loss due to circumstances such as: o highly volatile natural gas and crude oil prices; o our production being less than expected; or o a counterparty to one of our hedging transactions defaulting on our contractual obligations. We have experienced recurring significant operating losses. We recorded net losses from continuing operations for 2002 and 2003 of $55.2 million and $14.1 million, respectively. Lower natural gas and crude oil prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for our natural gas and crude oil operations. Accordingly, we capitalize the cost to acquire, explore for and develop natural gas and crude oil properties. Under full cost accounting rules, the net capitalized cost of natural gas and crude oil 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%. If net capitalized costs of natural gas and crude oil 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 earnings. The risk that we will be required to write-down the carrying value of natural gas and crude oil properties increases when natural gas and crude oil 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 natural gas and crude oil prices may have increased the ceiling applicable to the subsequent period. We have incurred ceiling limitation write-downs in the past. At June 30, 2002, for example, we recorded a ceiling limitation write-down of $28.2 million. We cannot assure you that we will not experience additional ceiling limitation write-downs in the future. Use of our net operating loss carryforwards may be limited. At December 31, 2004, we had, subject to the limitation discussed below, $184.0 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2022 if not utilized. In addition, 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. Moreover, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, we have established a valuation allowance of $73.2 million and $73.0 million for deferred tax assets at December 31, 2003 and 2004, respectively. We depend on our Chairman, President and CEO and the loss of his services could have an adverse effect on our operations. 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. Mr. Watson may terminate his employment agreement with us at any time on 30 days notice, but, if he terminates without cause, he would not be entitled to the severance benefits provided under the terms of that agreement. Mr. Watson is not precluded from working for, with or on behalf of a competitor upon termination of his employment with us. If Mr. Watson were no longer able or willing to act as our Chairman, the loss of his services could have an adverse effect on our operations. In addition, in connection with the Grey Wolf IPO, Abraxas, Grey Wolf and Mr. Watson agreed that Mr. Watson would continue to serve as Chief Executive Officer and President for Abraxas and as the Chief Executive Officer for Grey Wolf, with Mr. Watson devoting two-thirds 11 of his time to his positions and duties with Abraxas and one-third of his time to his position and duties with Grey Wolf. Risks Related to Our Industry We may not find any commercially productive natural gas or crude oil reservoirs. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our capital investment. Drilling for natural gas and crude oil 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. The inherent risk of not finding commercially productive reservoirs will be compounded by the fact that 49% of our total estimated proved reserves at December 31, 2004 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. In addition, our properties may be susceptible to drainage from production by other operations on adjacent properties. If the volume of natural gas and crude oil we produce decreases, our cash flow from operations will decrease. We operate in a highly competitive industry which may adversely affect our operations, including our ability to secure drilling equipment to service our core areas. We operate in a highly competitive environment. The principal resources necessary for the exploration and production of natural gas and crude oil are leasehold prospects under which natural gas and crude oil reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of natural gas and crude oil operations. We must compete for such resources with both major natural gas and crude oil companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. In the past, we have had difficulty securing drilling equipment in certain of our core areas. 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. Market conditions for natural gas and crude oil, and particularly volatility of prices for natural gas and crude oil, 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 natural gas and crude oil. 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. Lower prices may also make it uneconomical for us to increase or even continue current production levels of natural gas and crude oil. Prices for natural gas and crude oil are subject to large fluctuations in response to relatively minor changes in the supply and demand for natural gas and crude oil, market uncertainty and a variety of other factors beyond our control, including: o changes in foreign and domestic supply and demand for natural gas and crude oil; o political stability and economic conditions in oil producing countries, particularly in the Middle East; o general economic conditions. o Domestic and foreign governmental regulation; and o The price and availability of alternative fuel sources. In addition to decreasing our revenue and cash flow from operations, low or declining natural gas and crude oil prices could have additional material adverse effects on us, such as: 12 o reducing the overall volume of natural gas and crude oil that we can produce economically o reducing our borrowing base under the new credit facility; and o thereby adversely affecting our revenue, profitability and cash flow and our ability to perform our obligations with respect to the notes; and o impairing our borrowing capacity and our ability to obtain equity capital. Estimates of our proved reserves and future net revenue are uncertain and inherently imprecise. The process of estimating natural gas and crude oil reserves is complex involving decisions and assumptions in the evaluating available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, natural gas and crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and crude oil 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 report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploitation and development, prevailing natural gas and crude oil prices and other factors, many of which are beyond our control. 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 natural gas and crude oil reserves, future net revenue from proved reserves and the PV-10 thereof for the natural gas and crude oil gas properties described in this report are based on the assumption that future natural gas and crude oil prices remain the same as crude oil and natural gas prices at December 31, 2004. The sales prices as of such date used for purposes of such estimates were $41.01 per Bbl of crude oil and $4.94 per Mcf of natural gas. This compares with $31.03 per Bbl of crude oil and $5.05 per Mcf of natural gas as of December 31, 2003. These estimates also assume that we will make future capital expenditures of approximately $45.0 million in the aggregate through 2019, the majority expected to be incurred from 2005 to 2008, 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 in this report. The present value of future net revenues referred to in this report may not be the current market value of our estimated natural gas and crude oil 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 natural gas and crude oil 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 natural gas and crude oil industry in general will affect the accuracy of the 10% discount factor. Our operations are subject to numerous risks of natural gas and crude oil drilling and production activities. Our natural gas and crude oil drilling and production activities are subject to numerous risks, many of which are beyond our control. These 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 and discharges of toxic gases. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations. If any of these or other similar 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 13 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. Our natural gas and crude oil operations are subject to various Federal, state and local regulations that materially affect our operations. Matters regulated include 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 natural gas and crude oil, these agencies have restricted the rates of flow of natural gas and crude oil wells below actual production capacity. Federal, state and local laws regulate production, handling, storage, transportation and disposal of natural gas and crude oil, by-products from natural gas and crude oil and other substances and materials produced or used in connection with natural gas and crude oil 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 Natural Gas and Crude Oil 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 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 were subject to significant federal regulation. At the present time, however, all sales of our crude oil, natural gas, condensate and NGLs produced under private contracts may be sold at market prices. Congress could, however, re-enact price controls in the future. If controls that limit prices to below market rates are instituted, our revenue would be adversely affected. 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 ("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 14 of natural gas. For example, 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 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 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. 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. In summary, all of 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, 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 natural gas and crude oil industry historically has been very heavily regulated; thus there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future. State and Other Regulation All of the jurisdictions in which we own producing natural gas and crude oil properties have statutory provisions regulating the exploration for and production of natural gas and crude oil. 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 natural gas and crude oil properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from natural gas and crude oil 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 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. Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the State's more active review of rates, services and practices associated with the gathering and transportation of natural gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates. 15 For those operations on 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 natural gas and crude oil 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. Environmental Matters Our operations are subject to numerous federal, state 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 natural gas and crude oil 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 natural gas and crude oil 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 natural gas and crude oil. Although we utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may 16 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 natural gas and crude oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are usually causes of action based on negligence, trespass, nuisance, strict liability and fraud. United States federal regulations also require certain owners and operators of facilities that store or otherwise handle crude oil, such as us, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of crude oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to crude oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil. 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 reclamation 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. Title to Properties As is customary in the natural gas and crude oil industry, we make only a cursory review of title to undeveloped natural gas and crude oil 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/lessor 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 natural gas and crude oil properties, some of which are subject to immaterial encumbrances, easements and restrictions. The natural gas and crude oil 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, 2005, we had 47 full-time employees in the United States, including 3 executive officers, 3 non-executive officers, 1 petroleum engineer, 1 geologist, 5 managers, 1 landman, 10 administrative and support personnel and 23 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. 17 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 free of charge 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 operations are concentrated in South and West Texas with over 99% of the PV-10 of our natural gas and crude oil properties at December 31, 2004 located in those two regions. We operate 94% of our wells in Texas. During 2004, we drilled a total of 3 new wells (3 net) in Texas with a 66% 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 45 wells with average production of 217 net Bbls of crude oil and 4,924 net Mcf of natural gas per day for the year ended December 31, 2004. As of December 31, 2004 we had estimated net proved reserves in South Texas of 27.8 Bcfe (82% natural gas) with a PV-10 of $59.2 million, 61% 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 our then existing Ward County Montoya acreage by paying us $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 we were responsible for our pro rata share of drilling and development cost. The farmout agreement terminated in early January 2004 and accordingly, EOG has reassigned all unearned acreage to Abraxas. In total in West Texas we own an average 74% working interest in 166 wells with average daily production of 375 net Bbls of crude oil and NGLs and 7,139 net Mcf of natural gas per day for the year ended December 31, 2004. As of December 31, 2004, we had estimated net proved reserves in West Texas of 65.1 Bcfe (81% natural gas) with a PV-10 of $88.9 million, 45% of which was attributable to proved developed reserves. Wyoming We currently hold 54,874 contiguous acres in the Powder River Basin in east central Wyoming. We have drilled and operate 6 wells in Converse and Niobrara counties that were completed in the Turner, Muddy and Niobrara formations. We own a 100% working interest in these wells that produced an average of 36 net barrels of crude oil per day in 2004. As of December 31, 2004 we had estimated net proved producing reserves in Wyoming of 137,345 barrels of crude oil with a PV-10 of $992,217. Exploratory and Developmental Acreage Our principal natural gas and crude oil properties consist of non-producing and producing natural gas and crude oil leases, including reserves of natural gas and crude oil in place. The following table indicates our interest in developed and undeveloped acreage applicable to continuing operations as of December 31, 2004:
Developed and Undeveloped Acreage As of December 31, 2004 ----------------------------------------------------------------------- Developed Acreage (1) Undeveloped Acreage (2) --------------------------------- ----------------------------------- Gross Acres (3) Net Acres (4) Gross Acres (3) Net Acres (4) --------------- --------------- --------------- ------------------ Texas 23,866 19,218 14,521 11,161 18 Wyoming 3,240 3,240 51,634 48,105 N. Dakota - - 80 24 --------------- --------------- --------------- ------------------ Total 27,106 22,458 66,235 59,290 =============== =============== =============== ==================
(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 natural gas and crude oil, 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 applicable to continuing operations, expressed separately for natural gas and crude oil, as of December 31, 2004:
Productive Wells (1) As of December 31, 2004 --------------------------------------------------------------------- State/Country Crude Oil Natural Gas ------------------ -------------------------------- ---------------------------------- Gross(2) Net(3) Gross(2) Net(3) --------------- -------------- --------------- ---------------- Texas 145.0 116.6 66.0 48.8 Wyoming 6.0 6.0 18.0 - N. Dakota - - 1.0 - --------------- -------------- --------------- ---------------- Total 151.0 122.6 85.0 48.8 =============== ============== =============== ================
(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 natural gas and crude oil reserves have been estimated as of January 1, 2005, January 1, 2004, and January 1, 2003, by DeGolyer and MacNaughton, of Dallas, Texas. Natural gas and crude oil 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 natural gas and crude oil and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. The following table sets forth certain information regarding estimates of our crude oil, natural gas liquids and natural gas reserves as of January 1, 2003, January 1, 2004 and January 1, 2005 relating to continuing operations.
Estimated Proved Reserves ---------------------------------------------------------- Proved Proved Total Developed Undeveloped Proved -------------- --------------- ------------------ As of January 1, 2005 Crude oil (MBbls) 1,878 1,223 3,101 NGLs (MBbls) - - - Natural gas (MMcf) 36,241 38,877 75,118 19 As of January 1, 2004 Crude oil (MBbls) 1,791 1,264 3,054 NGLs (MBbls) 95 170 265 Natural gas (MMcf) 39,371 40,831 80,202 As of January 1, 2003 Crude oil (MBbls) 1,646 1,317 2,963 NGLs (MBbls) 105 168 273 Natural gas (MMcf) 34,776 43,420 78,196 ------------------
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, natural gas and crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and crude oil 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 exploitation and development, prevailing natural gas and crude oil 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 natural gas and crude oil 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 natural gas and crude oil 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 $28.2 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." 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 natural gas and crude oil 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 natural gas and crude oil 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 natural gas and crude oil reserves, future net revenue from proved reserves and the PV-10 thereof for the natural gas and crude oil properties described in this report are based on the assumption that future natural gas and crude oil prices remain the same as natural gas and crude oil prices at December 31, 2004. The average sales prices as of such date used for purposes of such estimates were $41.01 per Bbl of crude oil and $4.94 per Mcf of natural gas. It is also assumed that we will make future capital expenditures of approximately $45.0 million in the aggregate, most of which is in the years 2005 through 2008, which are necessary to develop and realize the value of proved 20 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 natural gas and crude oil 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 Mcfe of production sold, for the three years ended December 31, 2004 related to continuing operations:
2002 2003 2004 --------------- -------------- --------------- Crude oil production (Bbls) 255,041 220,135 220,409 Natural gas production (Mcf) 5,471,589 4,780,739 4,403,030 Natural gas liquids production (Bbls) 8,970 9,439 8,875 Total production (Mmcfe) 7,056 6,158 5,779 Average sales price per Bbl of crude oil $ 24.34 $ 30.43 $ 40.12 Average sales price per Mcf of natural gas (1) $ 2.65 $ 4.77 $ 5.45 Average sales price per Bbl of natural gas liquids $ 14.43 $ 20.46 $ 26.32 Average sales price per Mcfe $ 2.95 $ 4.82 $ 5.72 Average cost of production per Mcfe produced (2) $ 1.08 $ 1.35 $ 1.48 ------------------
(1) Average sales prices are net of hedging activity. (2) Natural gas and crude oil 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. Drilling Activities The following table sets forth our gross and net working interests in exploratory and development wells drilled, related to continuing operations during the three years ended December 31, 2004:
2002 2003 2004 ----------------------------- ----------------------------- ------------------------- Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) ------------ ---------- ------------ ---------- ---------- -------- Exploratory(3) Productive(4) Crude oil - - 1.0 1.0 2.0 2.0 Natural gas - - - - - - Dry holes(5) - - - - - - ------------ ---------- ------------ ---------- ---------- -------- Total - - 1.0 1.0 2.0 2.0 ============ ========== ============ ========== ========== ======== 21 Development(6) Productive (4) Crude oil - - - - - - Natural gas 2.0 0.12 5.0 5.0 1.0 1.0 Dry holes (5) - - - - 1.0 1.0 ------------ ---------- ------------ ---------- ---------- -------- Total 2.0 0.12 5.0 5.0 2.0 2.0 ============ ========== ============ ========== ========== ======== ------------------
(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 natural gas or crude oil in an unproved area, to find a new reservoir in a field previously found to be producing natural gas or crude oil 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 natural gas or crude oil in sufficient quantities to justify completion as a natural gas or crude oil well. (6) A development well is a well drilled within the proved area of a natural gas or crude oil reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved natural gas or crude oil reserves. As of March 18, 2005 we had 6 wells in process of drilling and/or completing. 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 April 2006 at an aggregate base rate of $20,787 per month. We also have an office in Midland, Texas consisting of 570 square feet leased through February 2006 at an aggregate base rate of $380 per month. 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 of these properties are used for the storage of tubulars and production equipment. We also own 23 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 a limited partnership, of which Wamsutter Holdings, Inc. is the general partner (the "Partnership"), were named in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserted breach of contract, fraud and negligent misrepresentation by Abraxas and the Partnership related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by Abraxas 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. Abraxas and the Partnership appealed the District Court's judgment and on November 3, 2004, the U.S. Court of Appeals for the 10th Circuit affirmed the District Court's decision. On December 14, 2004, the U.S. Court of Appeals for the 10th Circuit entered a mandate for the District Court to enforce the judgment. As of December 27, 2004, the final judgment amount was approximately $1.55 million (which includes accrued and unpaid interest since February 2002). Abraxas has decided not to pursue further appeals and subsequent to December 31, 2004 has paid its portion of the final judgment, approximately $1 million, for which Abraxas had previously established a reserve. 22 Additionally, from time to time, Abraxas is involved in litigation relating to claims arising out of its operations in the normal course of business. At December 31, 2004, Abraxas was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on Abraxas. 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, 2004. 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 2005 annual meeting of shareholders and until his successor is duly elected and qualified. Robert L. G. Watson, age 54, 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. Prior to joining Abraxas, Mr. Watson was employed in various petroleum engineering positions with Tesoro Petroleum Corporation, a natural gas and crude oil 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 53, 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 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 natural gas and crude oil exploration and production company, from July 1989 to December 1992 and President of Clark Resources Corp., a natural gas and crude oil 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 43, was elected Executive Vice President and a director of Abraxas in July 1998. In December 1999, Mr. Carington resigned as a director of Abraxas. Prior to joining Abraxas, 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. 23 PART II Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Our 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 our common stock on the American Stock Exchange. Period High Low 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 $ 3.64 $ 1.29 Second Quarter 2.89 1.50 Third Quarter 2.37 1.09 Fourth Quarter 2.99 1.91 2005 First Quarter (Through March 18, 2005) $ 2.92 $ 1.97 Holders As of March 18, 2005, we had 36,813,758 shares of common stock outstanding and had approximately 1600 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 our Floating Rate Senior Secured Notes due 2009 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 As part of the October 2004 refinancing, we privately issued $125.0 million aggregate principal amount of Floating Rate Senior Secured Notes due 2009, Series A. On October 28, 2004, we sold the new notes to Guggenheim Capital Markets, LLC, which subsequently resold the new notes under Rule 144A, Rule 501(a) and Regulation S of the Securities Act of 1933, as amended. In connection with the October 2004 refinancing, Guggenheim Capital Markets, LLC received warrants to purchase up to 1,000,000 shares of our common stock at a purchase price of $0.01 per share pursuant to a Warrant entered into on October 28, 2004 (the "GCM Warrant"). The GCM Warrant was issued to Guggenheim pursuant to a private placement by us as an issuer under Section 4(2) of the Securities Act of 1933. From and after October 28, 2004 and until 5:00 P.M., New York time, on October 28, 2014, the holder of the GCM Warrant may from time to time exercise it, on any business day, for all or any part of the number of shares of our common stock purchasable thereunder. In order to exercise the GCM Warrant, in whole or in part, the holder must (i) deliver to us (x) a written notice of the holder's election to exercise the GCM Warrant, which notice shall be irrevocable and specify the number of shares of our common stock to be purchased and (y) the GCM Warrant, and (ii) pay to us the warrant price. The GCM Warrant permits payment upon exercise of the GCM Warrant to be made, at 24 the option of the holder, by: (i) delivery of a certified or official bank check in the amount of the warrant price; (ii) instructing us to withhold a number of shares of warrant stock then issuable upon exercise of the GCM Warrant with an aggregate fair value equal to the warrant price; or (iii) surrendering to us shares of our common stock previously acquired by the holder with an aggregate fair value equal to the warrant price. The GCM Warrant contains customary restrictions on transfer and anti-dilution provisions, including dilution caused by stock dividends, subdivisions, combinations, reorganizations, reclassifications, mergers, consolidations or disposition of assets. Pursuant to the GCM Warrant, we also agreed, in specified circumstances, to file a registration statement to cover the warrant stock underlying the GCM warrant. Durham Capital Corporation, also received a warrant to purchase up to 100,000 shares of our common stock at a purchase price of $0.01 per share (the "Durham Warrant"), pursuant to a private placement by us as an issuer under Section 4(2) of the Securities Act for advising us in connection with the October 2004 refinancing. The Durham Warrant was exercised in November 2004. We did not repurchase any of our registered equity securities in the fourth quarter of 2004. 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. 51
Year Ended December 31, -------------------------------------------------------------------------------- 2000 2001 2002 2003 2004 ---- ---- ---- ---- ---- (Dollars in thousands except per share data) Total revenue - continuing operations $ 32,886 $ 35,775 $ 21,541 $ 30,380 $ 33,854 Net income (loss) $ 8,449 (2) $ (19,718) (3) $ (118,527) (1) $ 55,920 (4) $ 11,167 (6) Net income (loss) - discontinued operations (3,985) (4,870) (63,355) 70,024 (4) 3,323 Net income (loss) - continuing operations 12,434 (14,848) (55,172) (14,104) 7,844 Net income (loss) per common share - diluted $ 0.26 $ (0.76) $ (3.95) $ 1.58 $ 0.29 Weighted average shares outstanding - diluted (in thousands) 22,616 25,789 29,979 35,364 (5) 38,895 Total assets $ 335,560 $ 303,616 $ 181,425 $ 126,437 $ 152,685 Long-term debt, excluding current maturities $ 207,081 $ 209,611 $ 201,850 $ 184,649 $ 126,425 Total stockholders' equity (deficit) $ (6,503) $ (28,585) $ (142,254) $ (72,203) $ (53,464)
(1) Includes ceiling limitation write-down of $116.0 million ($28.2 million related to continuing operations). (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 test write-down of $2.6 million in 2001, based on subsequent (March 22, 2002) realized prices, related to discontinued operations. (4) Includes gain on sale of foreign subsidiaries of $ 68.9 million in 2003. (5) For the year ended December 31, 2003, 711,928 shares were excluded from the calculation of diluted earnings per share since their inclusion would have been antidilutive. (6) Includes gain on debt extinguishment of $12.6 million and a deferred tax benefit of $6.1 million. 25 Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations Prior to February 2005, Grey Wolf Exploration Inc. was a wholly-owned Canadian subsidiary of Abraxas. In February 2005, Grey Wolf , closed on an initial public offering resulting in the substantial divestiture of our capital stock in Grey Wolf. As a result of the Grey Wolf IPO, and the significant divestiture of our interest in Grey Wolf, the results of operations of Grey Wolf are reflected in our Financial Statements and in this document as "Discontinued Operations" and our remaining operations are referred to in our Financial Statements and in this document as "Continuing Operations" or "Continued Operations". Unless otherwise noted, all disclosures are for continuing operations. The following is a discussion of our consolidated financial condition, results of continuing 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 primarily engaged in the development, and production of natural gas and crude oil. Historically we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a substantial inventory of low risk development opportunities, which provide a basis for significant production and reserve increases. In addition, we intend to expand upon our exploitation and development activities with complementary low risk exploration projects in our core areas of operation. We have incurred net losses in two 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 which significantly affect our results of operations including the following: o the sales prices of natural gas, natural gas liquids and crude oil ; o the level of total sales volumes of natural gas, natural gas liquids and crude oil; 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 2004. Prices remained strong during 2004 and have continued to remain strong during the beginning of 2005. The table below illustrates how natural gas prices fluctuated during 2003 and 2004. The table below contains the last three day average of NYMEX traded contracts price and the prices we realized during each quarter for 2003 and 2004, including the impact of our hedging activities.
Natural Gas Prices by Quarter (in $ per Mcf) Quarter Ended ---------------------------------------------------------------------------------------------------------------- Mar. 31, June 30, Sept. 30, Dec. 31, Mar 31, June 30, Sept. 30 Dec. 31 2003 2003 2003 2003 2004 2004 2004 2004 ---------- ---------- ----------- ---------- ---------- ---------- ---------- ----------- Index $6.61 $5.51 $5.10 $4.60 $5.69 $5.97 $5.85 $6.77 Realized $5.30 $5.05 $4.47 $4.29 $4.98 $5.52 $5.24 $6.14
26 The NYMEX natural gas price on March 18, 2005 was $7.27 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 2003 and 2004.
Crude Oil Prices by Quarter (in $ per Bbl) Quarter Ended ---------------------------------------------------------------------------------------------------------------- Mar. 31, June 30, Sept. 30, Dec. 31, Mar 31, June 30, Sept. 30 Dec. 31 2003 2003 2003 2003 2004 2004 2004 2004 ---------- ---------- ----------- ---------- ---------- ---------- ---------- ----------- Index $33.71 $29.87 $30.85 $29.64 $34.76 $38.48 $42.32 $49.46 Realized $33.36 $28.54 $29.55 $29.99 $34.18 $37.29 $42.43 $46.81
The NYMEX crude oil price on March 18, 2005 was $56.72 per Bbl. We seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. In 2002 and 2003, we experienced hedging losses of $1.5 million and $842,000, respectively. For the year ended December 31, 2004 we recognized a gain from hedging activities of approximately $118,000. Under the terms of our new revolving credit facility, we are required to maintain hedging positions with respect to not less than 25% nor more than 75% of our natural gas and crude oil production, on an equivalent basis, for a rolling six month period. As of December 31, 2004, we had the following hedges in place:
Time Period Notional Quantities Price ---------------------------------- -------------------------------------------- ---------------------- January 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 7,100 MMbtu of production per day Floor of $4.50 February 2005 400 Bbls of crude oil production per day Floor of $25.00 7,100 MMbtu of production per day Floor of $4.50 March 2005 400 Bbls of crude oil production per day Floor of $25.00 7,100 MMbtu of production per day Floor of $4.50 April 2005 400 Bbls of crude oil production per day Floor of $25.00 May - December 2005 9,500 MMbtu of production per day Floor of $5.00
Production Volumes. Because our proved reserves will decline as natural gas, natural gas liquids and crude oil are produced, unless we acquire additional properties containing proved reserves or conduct successful exploitation 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. We had capital expenditures for 2004 of $9.3 million and anticipate approximately $22.0 million, in 2005, which we expect will include the drilling or recompletion of approximately 16 wells. Capital spending limitations that existed under the terms of our prior senior credit agreement and our 11 1/2% notes due 2007 were removed in connection with the refinancing that closed in October 2004. As a result of the limitations, we were limited for most of 2004 in our ability to replace existing production with new production. If crude oil 27 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. Availability of Capital. As described more fully under "Liquidity and Capital Resources" below, our sources of capital going forward will primarily be cash from operating activities, funding under its new revolving credit facility, cash on hand, and if an appropriate opportunity presents itself, proceeds from the sale of properties. We currently have approximately $13.0 million of availability under our new revolving credit facility. Exploitation and Development Activity. We believe that our high quality asset base, high degree of operational control and large inventory of drilling projects position us for future growth. Our properties are concentrated in locations that facilitate substantial economies of scale in drilling and production operations and more efficient reservoir management practices. We operate 94% of the properties accounting for approximately 95% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. In addition, we have 47 proved undeveloped locations and have identified over 100 drilling and recompletion opportunities on our existing acreage, the successful development of which we believe could significantly increase our daily production and proved reserves. Our future natural gas and crude oil production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our natural gas and crude oil properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploitation activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploitation and development activities will result in increases in our proved reserves. In addition, approximately 49% of our total estimated proved reserves at December 31, 2004 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. For a more complete discussion of these risks please see "Risk Factors--We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition would be adversely affected." Borrowings and Interest. We currently have indebtedness of approximately $127 million and availability of $13.0 million under the new revolving credit facility. We paid interest under our 11 1/2% secured notes due 2007 by the issuance of additional notes, which caused our cash interest expense to be $3.6 million during 2003 and $7.6 million during 2004. In connection with the refinancing transactions completed in October 2004, interest on the new notes will be paid in cash. This increase in cash interest expense will require us to increase our production and cash flow from operations in order to meet our debt service requirements, as well as to fund the development of our numerous drilling opportunities. Outlook for 2005. As a result of final 2004 financial results and current market conditions, we have updated our operating and financial guidance for year 2005 as follows: Production: BCFE (approximately 80% gas)....................... 6.5 - 7.5 Exit Rate (Mmcfe/d)................................... 19-21 Price Differentials (Pre Hedge): $ Per Bbl.......................................... 0.55 $ Per Mcf.......................................... 0.75 Lifting Costs, $ Per Mcfe............................. 0.85 G&A, $ Per Mcfe....................................... 0.55 Capital Expenditures ($ Millions)..................... 22.0 Results of Operations Selected Operating Data. The following table sets forth certain of our operating data for the periods presented. All data has been restated to reflect continuing operations. 28
Years Ended December 31, --------------------------------------------------------------- (dollars in thousands, except per unit data) 2002 2003 2004 ------------------- ------------------- ------------------- Operating revenue: Crude oil sales............................. $ 6,208 $ 6,699 $ 8,843 NGLs sales ................................. 130 193 234 Natural gas sales........................... 14,497 22,818 23,996 Rig and other............................... 706 670 781 ------------------- ------------------- ------------------- Total operating revenues ................... $ 21,541 $ 30,380 $ 33,854 =================== =================== =================== Operating income (loss)..................... $ (28,082) $ 8,720 $ 10,972 Crude oil production (MBbls)................ 255.0 220.1 220.4 NGLs production (MBbls)..................... 9.0 9.4 8.9 Natural gas production (MMcf)............... 5,471.6 4,780.7 4,403.0 Average crude oil sales price (per Bbl) $ 24.34 $ 30.43 $ 40.12 Average NGLs sales price (per Bbl) $ 14.43 $ 20.46 $ 26.32 Average natural gas sales price (per Mcf) $ 2.65 $ 4.77 $ 5.45
Revenue and average sales prices are net of hedging activities. Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003 Operating Revenue. During the year ended December 31, 2004, operating revenue from crude oil, natural gas and natural gas liquids sales increased by $3.4 million from $29.7 million in 2003 to $33.1 million in 2004. The increase in revenue was primarily due to increased commodity prices realized in 2004 as compared to 2003. The increase in revenue due to commodity prices was partially offset by decreased production volumes. Higher commodity prices contributed $5.2 million to natural gas and crude oil revenue while reduced production volumes had a $1.8 million negative impact on revenue. Natural gas liquids volumes declined from 9.4 MBbls in 2003 to 8.9 MBbls in 2004. Crude oil sales volumes increased slightly from 220.1 MBbls in 2003 to 220.4 MBbls during 2004. The increase is primarily due to the production from new wells in Wyoming and west Texas brought onto production in 2004, offsetting natural field declines in other areas. Natural gas sales volumes decreased from 4.8 Bcf in 2003 to 4.4 Bcf in 2004. This decrease is primarily due to natural field declines. There were no significant wells brought on line in 2004, primarily due to significant restrictions on capital expenditures for most of the year. Average sales prices in 2004 net of hedging costs were: o $40.12 per Bbl of crude oil, o $26.32 per Bbl of natural gas liquids, and o $ 5.45 per Mcf of natural gas. Average sales prices in 2003 net of hedging costs were: o $30.43 per Bbl of crude oil, o $20.46 per Bbl of natural gas liquids, and o $ 4.77 per Mcf of natural gas. Lease Operating Expense. Lease operating expense, or LOE, increased slightly from $8.3 million in 2003 to $8.6 million in 2004. The increase in LOE was primarily due to higher production taxes associated with higher commodity prices in 2004 as compared to 2003. Our LOE on a per Mcfe basis for the year 29 ended December 31, 2004 was $1.48 per Mcfe compared to $1.35 for 2003, primarily due to the decrease in production volumes. G&A Expense. G&A expense increased from $4.0 million in 2003 to $5.1 million in 2004. The increase in G&A expense was primarily due to performance bonuses in 2004. Our G&A expense on a per Mcfe basis increased from $0.65 in 2003 to $0.89 in 2004. The increase in the per Mcfe cost was due to increased expense and to lower production volumes in 2004 as compared to 2003. 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 $1.3 million to stock based compensation expense in 2004 related to these repricings, compared to $1.1 million during 2003. The increase is due to the increase in the price of our common stock in 2004. DD&A Expense. Depreciation, depletion and amortization expense decreased from $7.6 million in 2003 to $7.2 million in 2004. The decrease in DD&A was primarily due to decreased production volumes in 2004. Our DD&A expense on a per Mcfe basis for 2004 was $1.25 per Mcfe as compared to $1.24 per Mcfe in 2003. Interest Expense. Interest expense increased from $16.3 million to $17.9 million for 2004 compared to 2003. The increase in interest expense was due to increased debt levels in 2004, prior to the refinancing completed in October 2004. The increase in debt was primarily due to the payment of interest by the issuance of new notes related to the 11 1/2% notes due 2007. Financing Cost. Financing cost in 2004 was $1.7 million compared to $4.4 million in 2003. Financing cost represent costs related to refinancing activities, which do not qualify for amortization over the life of the debt. Financing costs in 2003 were related to the restructuring transaction, which occurred in January 2003. The 2004 costs relate to the refinancing activities during 2004. Income from discontinued operations. Income from discontinued operations was $3.3 million in 2004 compared to $70.0 million in 2003. This represents income from our Canadian subsidiary, which was sold in February 2005. Income in 2003 included a gain on the sale of foreign subsidiaries in January 2003 of $68.9 million. Excluding this gain, income in 2003 would have been $1.1 million. The increase in income in 2004, exclusive of the gain, was due to increased production and higher commodity prices in 2004 as compared to 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 increased by $8.9 million from $20.8 million in 2002 to $29.7 million in 2003. The increase in revenue was primarily due to increased commodity prices realized during 2003. The increase in natural gas and crude oil revenue resulting from increased prices was somewhat offset by decreased production volumes. Higher commodity prices contributed $11.5 million to natural gas and crude oil revenue while reduced production volumes had a $2.6 million negative impact on revenue. Natural gas liquids volumes increased from 9.0 MBbls in 2002 to 9.4 MBbls in 2003. Crude oil sales volumes declined from 255.0 MBbls in 2002 to 220.1 MBbls during 2003. Crude oil production decreased due primarily to natural field declines. Natural gas sales volumes decreased from 5.5 Bcf in 2002 to 4.8 Bcf in 2003. This decrease in production volumes was primarily due to natural field declines and property sales in 2002. Limited drilling activity in 2002 and 2003 due to capital expenditure limitations also contributed to the decline in production volumes. 30 Average sales prices in 2003 net of hedging costs were: o $30.43 per Bbl of crude oil, o $20.46 per Bbl of natural gas liquids, and o $ 4.77 per Mcf of natural gas. Average sales prices in 2002 net of hedging costs were: o $24.34 per Bbl of crude oil, o $14.43 per Bbl of natural gas liquids, and o $ 2.65 per Mcf of natural gas. Lease Operating Expense. Lease operating expense, or LOE, increased from $7.6 million in 2002 to $8.3 million in 2003. The increase in LOE is 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 $1.35 per Mcfe compared to $1.08 for 2002, primarily due to the decrease in production volumes as well as the overall increase in expense. G&A Expense. General and administrative, or G&A, expense remained constant at $4.0 million in 2002 and 2003. Our G&A expense on a per Mcfe basis increased from $0.57 in 2002 to $0.65 in 2003. The increase in the per Mcfe cost was due primarily to lower production volumes in 2003 as compared to 2002. 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 expense decreased by $1.6 million from $9.2 million in 2002 to $7.6 million in 2003. The decrease in DD&A was primarily due to the ceiling limitation write-downs in the second quarter of 2002, and decreased production volumes during 2003. Our DD&A expense on a per Mcfe basis for 2003 was $1.24 per Mcfe as compared to $1.30 per Mcfe in 2002. Interest Expense. Interest expense decreased from $24.7 million to $16.3 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 $201.9 million as of December 31, 2002 compared to $184.6 million at December 31, 2003. Income from discontinued operations. Income from discontinued operations was $70.0 million in 2003 compared to a loss of $63.4 million in 2002. This represents income from our Canadian subsidiary, which was sold in February 2005. The loss in 2002 was primarily due to a ceiling limitation writedown in that year of approximately $87.8 million offset by a deferred tax benefit of $29.7 million. The income in 2003 was primarily due to a gain on the sale of Canadian subsidiaries in January 2003 of $68.9 million. Ceiling Limitation Write-down. We record the carrying value of our natural gas and crude oil 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 Natural gas and crude oil Activities". At June 30, 2002, our net capitalized costs of natural gas and crude oil properties exceeded the present value of our estimated proved reserves by $28.2 million. These amounts were calculated considering June 30, 2002 prices of $26.12 per Bbl for crude oil and $2.16 per 31 Mcf for natural gas as adjusted to reflect the expected realized prices for each of the full cost pools. At December 31, 2003 and 2004 our net capitalized cost of natural gas and crude oil properties did not exceed the present value of our estimated reserves, plus the cost of properties not being amortized and the lower of cost of fair value of unproved properties being included in cost being amortized, less related income taxes, due to increased commodity prices, as such, no write-down was recorded in 2003 or 2004. 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 natural gas and crude oil assets increases when natural gas and crude oil 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 reserves are revised downward, a further write-down of the carrying value of our natural gas and crude oil properties may be required. Liquidity and Capital Resources General. The natural gas and crude oil 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 additional natural gas and crude oil properties; and o production and transportation facilities. The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our 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 going forward will primarily be cash from operating activities, funding under our new revolving credit facility, cash on hand, and if an appropriate opportunity presents itself, proceeds from the sale of properties. However, under the terms of the notes, proceeds of optional sales of our assets that are not timely reinvested in new natural gas and crude oil assets will be required to be used to reduce indebtedness and proceeds of mandatory sales must be used to repay or redeem indebtedness. Working Capital (Deficit). The following discussion represents working capital from continuing operations. At December 31, 2004 our current liabilities of approximately $11.9 million exceeded our current assets of $8.0 million resulting in a working capital deficit of $3.9 million. This compares to a working capital deficit of $2.0 million as of December 31, 2003. Current liabilities as of December 31, 2004 consisted of trade payables of $5.6 million, revenues due third parties $2.4 million, accrued interest of $2.2 million and other accrued liabilities of $ 1.6 million. Capital Expenditures. Capital expenditures related to our continuing operations in 2002, 2003 and 2004 were $5.1 million, $9.2 million and $9.3 million, respectively. The table below sets forth the components of these capital expenditures for the three years ended December 31, 2004.
Year Ended December 31, 2002 2003 2004 ------------------ ----------------- --------------- (dollars in thousands) Expenditure category: Development $ 4,944 $ 9,158 $ 9,088 Facilities and other 126 36 181 ------------------ ----------------- ---------------- Total $ 5,070 $ 9,194 $ 9,269 ================== ================= ================
32 During 2002, 2003 and 2004, capital expenditures were primarily for the development of existing properties. We anticipate making capital expenditures for 2005 of approximately $22.0 million, which we expect will include development activities related to approximately 16 projects. 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 natural gas and crude oil 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 natural gas and crude oil production volumes decreases caused by natural field declines and sales of producing properties, if any. Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities, related to continuing operations, are summarized in the following table and discussed in further detail below:
2002 2003 2004 -------------- ------------- ------------ (dollars in thousands) Net cash provided by operating activities $ 2,148 $ 11,479 $ 27,000 Net cash provided by (used in) investing activities 4,655 (9,194) (9,269) Net cash used in financing activities (9,692) (88,652) (65,684) -------------- ------------- ------------ Total $ (2,889) $ (86,367) $ (47,953) ============== ============= ============
Operating activities for the year ended December 31, 2004 provided us with $27.0 million of cash. Expenditures in 2004 of approximately $9.3 were primarily for the development of natural gas and crude oil properties. Financing activities used $65.7 million during 2004, primarily for payments on long-term debt and deferred financing fees. Operating activities for the year ended December 31, 2003 provided us with $11.5 million of cash. Investing activities used $9.2 million during 2003. Financing activities used $88.7 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 $9.2 million in exploitation and development expenditures. Expenditures in 2003 were primarily for the development of natural gas and crude oil properties. Operating activities for the year ended December 31, 2002 provided us $2.1 million of cash. Investing activities provided $4.7 million during 2002. Our investing activities included the sale of properties which provided $9.8 million, and the use of $5.1 million primarily for the development of producing properties. Financing activities used $9.7 million during 2002, relating primarily to payments on long-term debt. Future Capital Resources. We currently have four principal sources of liquidity going forward: (i) cash from operating activities, (ii) funding under our new revolving credit facility, (iii) cash on hand, and (iv) if an appropriate opportunity presents itself, the sale of producing properties. While we are no longer subject to the $10 million limitation on capital expenditures under our 11 1/2% secured notes due 2007, covenants under the indenture for the new notes and the new revolving credit facility restrict our use of cash from operating activities, cash on hand and any proceeds from asset sales. Under the terms of the notes, proceeds of optional sales of our assets that are not timely reinvested in new natural gas and crude oil assets will be required to be used to reduce indebtedness and proceeds of mandatory sales must be used to redeem indebtedness. The terms of the notes and the new revolving credit facility also substantially restrict our ability to: o incur additional indebtedness; o grant liens; 33 o pay dividends or make certain other restricted payments; 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. Our cash flow from operations depends heavily on the prevailing prices of natural gas and crude oil and our production volumes of natural gas and crude oil. 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 flow 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 new revolving credit facility, future natural gas and crude oil price declines would have a material adverse effect on our overall results, and therefore, our liquidity. Low natural gas and crude oil prices could also negatively affect our ability to raise capital on terms favorable to us. Our cash flow from operations will also depend upon the volume of natural gas and crude oil that we produce. Unless we otherwise expand reserves, our production volumes will decline as reserves are produced. Due to sales of properties in 2002 and January 2003, and restrictions on capital expenditures under the terms of our old notes, we now have significantly reduced reserves and production as compared with pre-2003 levels. In the future, if an appropriate opportunity presents itself, 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, 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 primarily pursuing these activities since January 1, 2003, we have not been able to fully replace the production volumes lost from natural field declines and property sales. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive natural gas or crude oil reservoirs will be found. The risk of not finding commercially productive reservoirs will be compounded by the fact that 49% of our total estimated proved reserves at December 31, 2004 were undeveloped. If the volume of natural gas and crude oil we produce decreases, our cash flow from operations will decrease. Our total indebtedness and cash interest expense as a result of issuing the new notes and entering into the new revolving credit facility require us to increase our production and cash flow from operations in order to meet our debt service requirements, as well as to fund the development of our numerous drilling opportunities. The ability to satisfy these new obligations will depend upon our drilling success as well as prevailing commodity prices. 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, 2004.
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) $ 126,425 $ - $ - $ 1,425 $ 125,000 Operating Leases (2) 338 254 84 - -
34 (1) These amounts represent the balances outstanding under Floating Rate Senior Secured Notes due 2009 and the new credit facility. These repayments assume that interest will be will be paid on an as due and that we will not draw down additional funds thereunder. (2) These amounts represent office lease obligations, expiring in 2006. Contingencies. In 2001, Abraxas and a limited partnership, of which Wamsutter Holdings, Inc. is the general partner (the "Partnership"), were named in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserted breach of contract, fraud and negligent misrepresentation by Abraxas and the Partnership related to the responsibility for year 2000 ad valorem taxes on natural gas and crude oil properties sold by Abraxas 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. Abraxas and the Partnership appealed the District Court's judgment and on November 3, 2004, the U.S. Court of Appeals for the 10th Circuit affirmed the District Court's decision. On December 14, 2004, the U.S. Court of Appeals for the 10th Circuit entered a mandate for the District Court to enforce the judgment. As of December 27, 2004, the final judgment amount was approximately $1.55 million (which includes accrued and unpaid interest since February 2002). Abraxas has decided not to pursue further appeals and has paid its portion of the final judgment, approximately $1 million, for which Abraxas had previously established a reserve. Other obligations. We make and will continue to make substantial capital expenditures for the acquisition, exploitation development and production of crude oil and natural gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments 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 October 2004 resulted in the redemption of our 11 1/2% secured notes due 2007 and terminating our previous senior credit facility with the proceeds from: o the issuance of $125 million aggregate principal amount of floating rate senior secured notes due 2009; o the proceeds from our $25 million bridge loan; and o the payment to us by Grey Wolf of $35 million from the proceeds of Grey Wolf's $35 million term loan. In connection with the Grey Wolf IPO completed in February 2005, net proceeds of approximately $37 million from the offering by Grey Wolf of treasury shares were used to repay Grey Wolf's term loan in its entirety and eliminate its working capital deficit. Net proceeds of approximately $20 million from the secondary shares offered by Abraxas were used to reduce the amount outstanding under its bridge loan to approximately $5.4 million. On March 24, 2005, the Company was advised of the underwriter's intent to exercise 3.5 million of the over allotment shares. Closing for this exercise is scheduled for March 31, 2005 and will provide approximately $7.5 million that Abraxas will utilize to payoff the remaining balance of its Bridge Loan. The remaining proceeds of approximately $2 million will be used to pay down the Company's revolving credit facility to, effectively, zero. The following table sets forth our long-term indebtedness as of December 31, 2003 and 2004 35
Long Term Indebtedness December 31, -------------------------------- 2003 2004 ----------------- -------------- (in thousands) 11 1/2% secured notes due 2007 .................................... $ 137,258 $ - Senior credit agreement .......................................... 47,391 - Floating rate senior secured notes due 2009........................ - 125,000 Senior secured revolving credit facility........................... - 1,425 ----------------- --------------- 184,649 126,425 Less current maturities ........................................... - - ----------------- --------------- $ 184,649 $ 126,425 ================= ===============
Floating Rate Senior Secured Notes due 2009. In connection with the October 2004 financial restructuring, Abraxas issued $125 million in principal aggregate amount of Floating Rate Senior Secured Notes due 2009. The new notes will mature on December 1, 2009 and began accruing interest from the date of issuance, October 28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The initial interest rate on the new notes is 9.72% per annum. The interest will be reset semi-annually on each June 1 and December 1, commencing on June 1, 2005. Interest is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on June 1, 2005. The new notes rank equally among themselves and with all of our unsubordinated and unsecured indebtedness, including our new credit facility and senior in right of payment to our existing and future subordinated indebtedness, including the bridge loan. Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has unconditionally guaranteed, jointly and severally, the payment of the principal, premium and interest including any additional interest) on, the new notes on a senior secured basis. In addition, any other subsidiary or affiliate of ours, that in the future guarantees any other indebtedness with us, or our restricted subsidiaries, will also be required to guarantee the new notes. The new notes and the Subsidiary Guarantors' guarantees thereof, together with our new credit facility and the Subsidiary Guarantors' guarantees thereof, are secured by shared first priority perfected security interests, subject to certain permitted encumbrances, in all of our and each of our restricted subsidiaries' material property and assets, including substantially all of our and their natural gas and crude oil properties and all of the capital stock (or in the case of an unrestricted subsidiary that is a controlled foreign corporation, up to 65% of the outstanding capital stock) of any entity, owned by us and our restricted subsidiaries (collectively, the "Collateral"). After April 28, 2007, we may redeem all or a portion of the new notes at the redemption prices set forth in the indenture with U.S. Bank National Association under which the new notes were issued, plus accrued and unpaid interest to the date of redemption. Prior to that date, we may redeem up to 35% of the aggregate original principal amount of the new notes using the net proceeds of one or more equity offerings, in each case at the redemption price equal to the product of (i) the principal amount of the new notes being so redeemed and (ii) a redemption price factor of 1.00 plus the per annum interest rate on the new notes (expressed as a decimal) on the applicable redemption date plus accrued and unpaid interest to the applicable redemption date, provided certain conditions are also met. If we experience specific kinds of change of control events, each holder of new notes may require us to repurchase all or any portion of such holder's new notes at a purchase price equal to 101% of the principal amount of the new notes, plus accrued and unpaid interest to the date of repurchase. The indenture governing the new notes contains covenants that, among other things, limit our ability to: o incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock; 36 o transfer or sell assets; o create liens on assets; o pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions; o engage in transactions with affiliates; o guarantee other indebtedness; o permit restrictions on the ability of our subsidiaries to distribute or lend money to us; o cause a restricted subsidiary to issue or sell its capital stock; and o consolidate, merge or transfer all or substantially all of the consolidated assets of our and our restricted subsidiaries. The indenture also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, including our new credit facility and bridge loan, bankruptcy, and material judgments and liabilities. Senior Secured Revolving Credit Facility. On October 28, 2004, we entered into an agreement for a new revolving credit facility having a maximum commitment of $15 million, which includes a $2.5 million subfacility for letters of credit. Availability under the new revolving credit facility is subject to a borrowing base consistent with normal and customary natural gas and crude oil lending transactions. Outstanding amounts under the new revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, National Association plus 1.00%. Subject to earlier termination rights and events of default, the stated maturity date under the new revolving credit facility is October 28, 2008. We are permitted to terminate the new revolving credit facility, and under certain circumstances, may be required, from time to time, to permanently reduce the lenders' aggregate commitment under the new revolving credit facility. Such termination and each such reduction is subject to a premium equal to the percentage listed below multiplied by the lenders' aggregate commitment under the new revolving credit facility, or, in the case of partial reduction, the amount of such reduction. Year % Premium -------------- -------------------- 1 1.5 2 1.0 3 0.5 4 0.0 Each of our current subsidiaries has guaranteed, and each of our future restricted subsidiaries will guarantee, our obligations under the new revolving credit facility on a senior secured basis. In addition, any other subsidiary or affiliate of ours, that in the future guarantees any of our other indebtedness or of its restricted subsidiaries will be required to guarantee our obligations under the new revolving credit facility. Obligations under the new revolving credit facility are secured, together with the new notes, by a shared first priority perfected security interest, subject to certain permitted encumbrances, in all of our and each of our restricted subsidiaries' material property and assets, including substantially all of our and their natural gas and crude oil properties and all of the capital stock (or in the case of an unrestricted subsidiary that is a controlled foreign corporation, up to 65% of the outstanding capital stock) in any entity, owned by us and our restricted subsidiaries. 37 Under the new revolving credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. The new revolving credit facility requires us to maintain a minimum net cash interest coverage and also requires us to enter into hedging agreements on not less than 25% or more than 75% of our projected natural gas and crude oil production. In addition to the foregoing and other customary covenants, the new revolving credit facility contains a number of covenants that, among other things, restrict Abraxas' ability to: o incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock; o transfer or sell assets; o create liens on assets; o pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions; o engage in transactions with affiliates; o guarantee other indebtedness; o make any change in the principal nature of our business; o prepay, redeem, purchase or otherwise acquire any of our or our restricted subsidiaries' indebtedness; o permit a change of control; o directly or indirectly make or acquire any investment; o cause a restricted subsidiary to issue or sell our capital stock; and o consolidate, merge or transfer all or substantially all of the consolidated assets of Abraxas and our restricted subsidiaries. The new revolving credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities, and is subject to an Intercreditor, Security and Collateral Agency Agreement, which specifies the rights of the parties thereto to the proceeds from the Collateral. Abraxas' New $25 Million Second Lien Increasing Rate Bridge Loan. On October 28, 2004, Abraxas borrowed $25 million under its new bridge loan. Interest on the bridge loan currently accrues at a rate of 12.0% per annum until October 28, 2005, and is payable monthly in cash. Interest on the bridge loan will thereafter accrue at a rate of 15.0% per annum, and will be payable in-kind. Subject to earlier termination rights and events of default, the stated maturity date under the bridge loan is October 28, 2010. The bridge loan is classified as liabilities related to assets held for sale in this document, and was substantially repaid subsequent to December 31, 2004. Intercreditor Agreement. The holders of the new notes, together with the lenders under our new credit facility and bridge loan, are subject to an Intercreditor, Security and Collateral Agency Agreement, which specifies the rights of the parties thereto to the proceeds from the Collateral. The 38 Intercreditor Agreement, among other things, (i) creates security interests in the Collateral in favor of a collateral agent for the benefit of the holders of the new notes, the new credit facility lenders and the bridge loan lenders and (ii) governs the priority of payments among such parties upon notice of an event of default under the Indenture, the new credit facility or the bridge loan. So long as no such event of default exists, the collateral agent will not collect payments under the new credit facility documents, the indenture governing the new notes and other new note documents or the bridge loan documents (collectively, the "Secured Documents"), and all payments will be made directly to the respective creditor under the applicable Secured Document. Upon notice of such an event of default and for so long as an event of default exists, payments to each new credit facility lender, holder of the new notes and bridge loan lender from us and our current subsidiaries, other than Grey Wolf, and proceeds from any disposition of any collateral, will, subject to limited exceptions, be collected by the collateral agent for deposit into a collateral account and then distributed as provided in the following paragraph, provided, that, any payment made with proceeds from the sale or other disposition of Grey Wolf stock will be applied exclusively to pay amounts with respect to the bridge loan, and no such proceeds will be deposited into the collateral account or will be subject to the payment priority described in the following paragraph. Upon notice of any such event of default and so long as an event of default exists, funds in the collateral account will be distributed by the collateral agent generally in the following order of priority: first, to reimburse the collateral agent for expenses incurred in protecting and realizing upon the value of the Collateral; second, to reimburse the new credit facility administrative agent, the trustee and the bridge loan administrative agent, on a pro rata basis, for expenses incurred in protecting and realizing upon the value of the Collateral while any of these parties was acting on behalf of the Control Party (as defined below); third, to reimburse the new credit facility administrative agent, the trustee and the bridge loan administrative agent, on a pro rata basis, for expenses incurred in protecting and realizing upon the value of the Collateral while any of these parties was not acting on behalf of the Control Party; fourth, to pay all accrued and unpaid interest (and then any unpaid commitment fees) under the new credit facility; fifth, if, the collateral coverage value of three times the outstanding obligations under the new credit facility would be met after giving effect to any payment under this clause "fifth," to pay all accrued and unpaid interest on the new notes; sixth, to pay all outstanding principal of (and then any other unpaid amounts, including, without limitation, any fees, expenses, premiums and reimbursement obligations) the new credit facility; seventh, to pay all accrued and unpaid interest on the new notes (if not paid under clause "fifth"); eighth, to pay all outstanding principal of (and then any other unpaid amounts, including, without limitation, any premium with respect to) the new notes; ninth, to pay the bridge loan lenders all accrued and unpaid interest under the bridge loan; tenth, to pay all outstanding principal of (and then any other unpaid amounts, including, without limitation, any premium with respect to) the bridge loan; and eleventh, to pay each new credit facility lender, holder of the new notes, bridge loan lender and other secured party, on a pro rata basis, all other amounts outstanding under the new credit facility, the new notes and the bridge loan. To the extent there exists any excess monies or property in the collateral account after all obligations ours and our subsidiaries', other than Grey Wolf, under the new credit facility, the indenture and the new notes and 39 the bridge loan are paid in full, the collateral agent will be required to return such excess to us. The collateral agent will act in accordance with the Intercreditor Agreement and as directed by the "Control Party". Prior to the occurrence of any such event of default, the "Control Party" will be the holders of the new notes and the new credit facility lenders, acting as a single class, by vote of the holders of a majority of the aggregate principal amount of outstanding obligations under the new notes and the new credit facility. Upon notice of any such event of default, the bridge loan lenders will be the Control Party for 240 days following such notice. If a stay under the Bankruptcy Code occurs during such 240-day period, that period will be extended by the number of days during which that stay was effective. If the new credit facility lenders and holders of the new notes have not been paid in full by the end of such specified period, they will become the Control Party, acting as a single class, by vote of the holders of a majority of the aggregate principal amount of outstanding obligations under the new notes and the new credit facility. The Intercreditor Agreement provides that the lien on the assets constituting part of the Collateral that is sold or otherwise disposed of in accordance with the terms of each Secured Document may be released if (i) no default or event of default exists under any of the Secured Documents, (ii) we have delivered an officers' certificate to each of the collateral agent, the trustee, the new credit facility administrative agent and the bridge loan administrative agent, certifying that the proposed sale or other disposition of assets is either permitted or required by, and is in accordance with the provisions of, the applicable Secured Documents and (iii) the collateral agent has acknowledged such certificate. The Intercreditor Agreement provides for the termination of security interests on the date that all obligations under the Secured Documents are paid in full. The Grey Wolf term loan was paid in full in February 2005 with the proceeds of the Grey Wolf IPO. This loan is included in Liabilities related to assets held for sale in the accompanying financial statements. 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 our new revolving credit facility, we are required to maintain hedge positions on not less than 25% or more than 75% of our projected oil and gas production for a six month rolling period. See "--Quantitative and Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further information. Net Operating Loss Carryforwards At December 31, 2004, we had, subject to the limitation discussed below, $184.0 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2022 if not utilized. Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, we have established a valuation allowance of $73.2 million and $73.0 million for deferred tax assets at December 31, 2003 and 2004, respectively. 40 Related Party Transactions Accounts receivable - Other in the consolidated balance sheets includes approximately $35,558 and $ 0 as of December 31, 2003 and 2004, respectively, representing amounts due from officers relating to advances made to employees. Abraxas has adopted a policy that transactions between Abraxas and its officers, directors, principal stockholders, or affiliates of any of them, will be on terms no less favorable to Abraxas than can be obtained on an arm's length basis in transactions with third parties and must be approved by the vote of at least a majority of the disinterested directors. Critical Accounting Policies The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Natural gas and crude oil Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in natural gas and crude oil activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploitation and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploitation 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 natural gas and crude oil 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 natural gas and crude oil 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 natural gas and crude oil 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. We have experienced this situation several times over the years, most recently in 2002. Our natural gas and crude oil 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 natural gas and crude oil 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 and the cost of properties not being amortized, less income taxes. If net capitalized costs of natural gas and crude oil 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 natural gas and crude oil properties increases when natural gas and crude oil 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 natural gas and crude oil prices may have increased the ceiling applicable to the subsequent period. 41 For the year ended December 31, 2002, we recorded a write-down of approximately $28.2 million related to continuing operations. 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 Proved Natural Gas and Crude Oil Reserves. 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. Our 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, we 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 we record 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. 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. 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 natural gas and crude oil prices. Results of those hedging transactions are reflected in natural gas and crude oil sales. Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," was effective for us 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. In 2003 we elected out of hedge accounting as prescribed by SFAS 133. Accordingly all derivatives, whether designated in hedging relationships or not, are required to be recorded at fair value on our balance sheet. Changes in fair value of contracts are recognized in earnings in the current period. Due to the volatility of natural gas and crude oil 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 and 2004 the net market value of our derivatives was an asset of $21,136 and $528,165 respectively. 42 New Accounting Pronouncements In November 2004 , the FASB issued SFAS No. 151, entitled " Inventory Costs - an amendment of ARB 43, chapter. The purpose of this statement is to clarify the accounting for abnormal amounts of idle facilities expense, freight, handling cost and wasted material. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We are evaluating the effect of this statement on our operations and do not expect it to impact our financial statements. In December 2004 the FASB issued "Summary of Statement No. 123 (revised 2004), Share-Based Payment. This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for: (1) equity instruments of the enterprise or (2) liabilities that are based on the fair value of the enterprise's equity instruments or that may be settled by the issuance of such equity instruments. The proposed statement would eliminate the ability to account for share-based compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued to Employees" and generally would require instead that such transactions be accounted for using a fair value-based method. As proposed, this statement is be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. We are currently evaluating what effect this statement will have on our financial position or results of operations. In December 2004 the FASB issued FASB No. 153, entitled " Exchanges of Nonmonetary Assets - an amendment of ABP Opinion No. 29". The guidance in ABP Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that Opinion, however, included certain exceptions to that principle. This statement amends Opinion 29 to eliminate the exception for nonmonetary of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The statement is effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005. We do not anticipate this statement impacting our financial statements. In September 2004, the Securities and Exchange Commission issued "Staff Accounting Bulletin No. 106" (SAB No. 106). SAB No. 106 applies to companies using the full cost method of accounting for oil and gas properties and equipment costs. SAB No. 106 affects the way in which companies calculate their full cost ceiling limitation (including asset retirement cost related to proved developed properties in the calculation of the ceiling) and the way companies calculate depletion on oil and gas properties (only asset retirement cost for new recompletions and new wells will be included in future development costs in calculating depletion rates). The Company does not anticipate that adoption of SAB No 106 will have a significant inpact on its financial position or results of operations. Item 7A. Quantitative and Qualitative Disclosures about Market Risk Commodity Price Risk As an independent natural gas and crude oil 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 natural gas and crude oil 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 natural gas and crude oil 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, 2004, a 10% 43 decline in crude oil, natural gas and natural gas liquids prices would have reduced our operating revenue and cash flow by approximately $3.3 million for the year. Hedging Sensitivity On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. In 2003 we elected not to designate derivative instruments as hedges. Accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded in current oil and gas revenue. Under the terms of our new revolving credit facility, we are required to maintain hedging positions with respect to not less than 25% nor more than 75% of our natural gas and crude oil production for a rolling six month period. All hedge transactions are subject to our risk management policy, which has been approved by the Board of Directors. As of December 31, 2004, we had the following hedges in place:
Time Period Notional Quantities Price --------------------------- ------------------------------------------ ---------------------- January 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 February 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 March 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 April 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 May - December 2005 9,500 MMbtu of production per day Floor of $5.00
Interest rate risk At December 31, 2004, as a result of the financial restructuring that occurred in October 2004, we had $125.0 million in outstanding indebtedness under the floating rate senior secured notes due 2009. The notes bear interest at a per annum rate of six-month LIBOR plus 7.5%. The rate is redetermined on June 1 and December 1 of each year, beginning June 1, 2005. The current rate on the new notes is 9.72%. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.3 million on an annual basis. At December 31, 2004 we had $1.4 million of outstanding indebtedness under our new revolving credit facility. Interest on this facility accrues at the prime rate announced by Wells Fargo Bank plus 1.00%. For every percentage point increase in the announced prime rate, our interest expense would increase by approximately $14,000 on an annual basis. Item 8. Financial Statements For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None 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 our "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 44 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. Item 9B. Other Information None. 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 2005 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 our 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, We believe that all our directors and executive officers during 2004 complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act. Item 11. Executive Compensation There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2005 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 and Related Stockholder Matters There is incorporated in this Item 12 by reference that portion of our definitive proxy statement for the 2005 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 2005 Annual Meeting of Stockholders which appears therein under the caption "Certain Transactions." 45 Item 14. Principal Accounting Fees and Services There is incorporated in this Item 14 by reference that portion of our definitive proxy statement for the 2005 Annual Meeting of Stockholders which appears therein under the caption "Principal Auditor Fees and Services." PART IV Item 15. Exhibits, Financial Statement Schedules (a)1. Consolidated Financial Statements Page
Report of BDO Seidman LLP, Independent Registered Public Accounting Firm...................F-2 Report of Deloitte & Touche LLP, an Independent Registered Public Accounting Firm...........F-3 Consolidated Balance Sheets, December 31, 2003 and 2004................................................................F-4 Consolidated Statements of Operations, Years Ended December 31, 2002, 2003 and 2004..............................................F-6 Consolidated Statements of Stockholders' Deficit Years Ended December 31, 2002, 2003 and 2004 ............................................F-7 Consolidated Statements of Cash Flows Years Ended December 31, 2002, 2003 and 2004..............................................F-9 Consolidated Statements of Other Comprehensive Income (Loss) Years Ended December 31, 2002, 2003 and 2004.............................................F-11 Notes to Consolidated Financial Statements.................................................F-12
(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 our 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). 46 3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to our 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 our 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 our Annual Report on Form 10-K filed on March 31, 1995). 4.3 Indenture dated October 28, 2004, by and among Abraxas, as Issuer; the Subsidiary Guarantors party thereto and U.S. Bank National Association, as Trustee, relating to Abraxas' Floating Rate Senior Secured Notes Due 2009. (filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K filed on November 3, 2004). 4.4 Form of Rule 144A Global Note for Floating Rate Senior Secured Notes due 2009. (Filed as Exhibit A-1 to Exhibit 4.1 to Abraxas' Current Report on Form 8-K filed on November 3, 2004). 4.5 Form of Regulation S Global Note for Floating Rate Senior Secured Notes due 2009. (Filed as Exhibit A-2 to Exhibit 4.1 to Abraxas' Current Report on Form 8-K filed on November 3, 2004). 4.6 Form of Accredited Investor Certificated Note for Floating Rate Senior Secured Notes due 2009. (Filed as Exhibit A-3 to Exhibit 4.1 to Abraxas' Current Report on Form 8-K filed on November 3, 2004). *10.1 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")). *10.2 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as Exhibit 10.5 to the 1996 Exchange Offer Registration Statement). *10.3 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). *10.4 Abraxas Petroleum Corporation Amended and Restated 1994 Long Term Incentive Plan. *10.5 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). 10.6 Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.30 to the 1993 S-1). 10.7 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). 47 10.8 Purchase Agreement dated as of October 21, 2004 by and among Abraxas Petroleum Corporation, the Subsidiary Guarantors signatory thereto and Guggenheim Capital Markets, LLC. (Filed as Exhibit 10.1 to Abraxas' Current Report on Form 8-K filed November 3, 2004). 10.9 Loan Agreement dated as of October 28, 2004 by and among Abraxas Petroleum Corporation, the Subsidiary Guarantors party thereto, Wells Fargo Foothill, Inc., as Arranger and Administrative Agent and the Lenders signatory thereto. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed November 3, 2004). 10.10 Loan Agreement dated as of October 28, 2004 by and among Abraxas Petroleum Corporation, the Subsidiary Guarantors party thereto, Guggenheim Corporate Funding, LLC, as Arranger and Administrative Agent and the Lenders signatory thereto. (Filed as Exhibit 10.3 to Abraxas' Current Report on Form 8-K filed November 3, 2004). *10.11 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the 2000 S-1 Registration Statement). *10.12 Employment Agreement between Abraxas and Chris E. Williford. (Filed as Exhibit 10.20 to the 2000 S-1 Registration Statement). *10.13 Employment Agreement between Abraxas and Robert W. Carington, Jr. (Filed as Exhibit 10.22 to the 2000 S-1 registration Statement). *10.14 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the S-3 Registration Statement). *10.15 Employment Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27 to the S-3 Registration Statement). *10.16 Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as Exhibit 10.28 to the S-3 Registration Statement). 10.17 Loan Agreement dated October 28, 2004 by and among Grey Wolf Exploration Inc., Guggenheim Corporate Funding, LLC as Arranger and Administrative Agent and the Lenders signatory thereto. (Filed as Exhibit 10.4 to Abraxas' Current Report on Form 8-K filed November 3, 2004). 10.18 Intercreditor, Security and Collateral Agency Agreement dated as of October 28, 2004 by and among Abraxas Petroleum Corporation, the Subsidiary Guarantors party thereto, Wells Fargo Foothill, Inc., Guggenheim Corporate Funding, LLC and U.S. Bank National Association. (Filed as Exhibit 10.5 to Abraxas' Current Report on Form 8-K filed November 3, 2004). 10.19 Warrant issued to Guggenheim Corporate Funding, LLC dated October 28, 2004. (Filed as Exhibit 10.6 to Abraxas' Current Report on Form 8-K filed November 3, 2004). 10.20 Exchange and Registration Rights Agreement dated October 28, 2004, by and among Abraxas Petroleum Corporation, the Subsidiary Guarantors signatory thereto, and Guggenheim Capital Markets, LLC. (Filed as Exhibit 10.1 to Abraxas' Quarterly Report on Form 10-Q filed November 12, 2004). 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) 48 23.2 Consent of Deloitte & Touche LLP (filed herewith). 23.3 Consent of DeGolyer and MacNaughton. (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. 49 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 29, 2005 Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated. Signature Name and Title Date --------- -------------- ---- /s/ Robert L.G. Watson Chairman of the Board, ------------------------ President (Principal Executive Robert L.G. Watson Officer) and Director March 29, 2005 /s/ Chris E. Williford Exec. Vice President and ------------------------ Treasurer (Principal Financial Chris E. Williford and Accounting Officer) March 29, 2005 /s/ Craig S. Bartlett, Jr. Director March 29, 2005 -------------------------- Craig S. Bartlett, Jr. /s/ Franklin A. Burke Director March 29, 2005 ---------------------- Franklin A. Burke /s/ Harold D. Carter Director March 29, 2005 ---------------------- Harold D. Carter /s/ Ralph F. Cox Director March 29, 2005 ---------------------- Ralph F. Cox /s/ Barry J. Galt Director March 29, 2005 ------------------ Barry J. Galt /s/ Dennis E. Logue Director March 29, 2005 ---------------------- Dennis E Logue /s/ James C. Phelps Director March 29, 2005 ---------------------- James C. Phelps /s/ Joseph A. Wagda Director March 29, 2005 ---------------------- Joseph A. Wagda 50 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page Abraxas Petroleum Corporation and Subsidiaries Report of Independent Registered Public Accounting Firm for the year ended December 31, 2003 and 2004...................................F-2 Report of Independent Registered Public Accounting Firm for the year ended December 31, 2002.................................................F-3 Consolidated Balance Sheets at December 31, 2003 and 2004...................F-4 Consolidated Statements of Operations for the years ended December 31, 2002, 2003 and 2004........................................F-6 Consolidated Statements of Stockholders' Deficit for the years ended December 31, 2002, 2003 and 2004........................................F-7 Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2003 and 2004........................................F-8 Consolidated Statements of Other Comprehensive Income (loss) for the years ended December 31, 2002, 2003 and 2004....................F-10 Notes to Consolidated Financial Statements .................................F-11 All other schedules are omitted because they are not required, are not applicable or the information required is included in the Consolidated Financial Statements or the notes thereto. F-1 Report of Independent Registered Public Accounting Firm Board of Directors and Stockholders Abraxas Petroleum Corporation We have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation as of December 31, 2003 and 2004 and the related consolidated statements of operations, stockholders' deficit, cash flows, and other comprehensive income (loss) for the years ended December 31, 2003 and 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Abraxas Petroleum Corporation at December 31, 2003 and 2004, and the results of its operations and its cash flows for the years ended December 31, 2003 and 2004, in conformity with accounting principles generally accepted in the United States of America. /s/ BDO Seidman, LLP Dallas, Texas February 28, 2005, except for Note 2 , as to which the date is March 24, 2005 F-2 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Abraxas Petroleum Corporation We have audited the accompanying consolidated statement of operations, stockholders' deficit, cash flows, and other comprehensive income (loss) of Abraxas Petroleum Corporation (the "Company") for the year 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 audit. We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the year ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. /s/ DELOITTE & TOUCHE LLP San Antonio, Texas March 10, 2003 (July 18, 2003 as to Note 17, March 28, 2005 as to the reclassification of the 2002 consolidated financial statements for discontinued operations referred to in Note 2) F-3
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS ASSETS December 31 -------------------------------------- 2003 2004 ------------------ ------------------- (Dollars in thousands) Current assets: Cash ................................................... $ - $ 1,284 Accounts receivable: Joint owners ....................................... 1,271 471 Oil and gas production sales ....................... 5,190 4,724 Other .............................................. 959 66 ------------------ ------------------- 7,420 5,261 Equipment inventory .................................... 782 735 Other current assets ................................... 418 752 ------------------ ------------------- 8,620 8,032 Assets held for sale.................................... 37,092 52,600 ------------------ ------------------- Total current assets................................ 45,712 60,632 Property and equipment: Oil and gas properties, full cost method of accounting: Proved ............................................. 288,559 297,647 Other property and equipment ......................... 2,749 2,930 ------------------ ------------------- Total .......................................... 291,308 300,577 Less accumulated depreciation, depletion, and amortization ....................................... 215,287 222,500 ------------------ ------------------- Total property and equipment - net ................. 76,021 78,077 Deferred financing fees net ............................... 4,410 7,618 Deferred tax asset......................................... - 6,060 Other assets .............................................. 294 298 ------------------ ------------------- Total assets ........................................... $ 126,437 $ 152,685 ================== =================== See accompanying notes to consolidated financial statements
F-4
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (CONTINUED) LIABILITIES AND STOCKHOLDERS' DEFICIT December 31 -------------------------------------- 2003 2004 ------------------ ------------------- (Dollars in thousands) Current liabilities: Accounts payable .......................................... $ 5,019 $ 5,622 Joint interest oil and gas production payable ............. 2,056 2,443 Accrued interest .......................................... 2,340 2,170 Other accrued expenses .................................... 1,228 1,654 ------------------ ------------------- 10,643 11,889 Liabilities related to assets held for sale................ 2,572 66,947 ------------------ ------------------- Total current liabilities................................ 13,215 78,836 Long-term debt ............................................... 184,649 126,425 Future site restoration ..................................... 776 888 Stockholders' equity (deficit): Common stock, par value $.01 per share - authorized 200,000,000 shares; issued 36,024,308 and 36,597,045 at December 31, 2003 and 2004 respectively............ 360 366 Additional paid-in capital ................................ 141,835 146,185 Receivables from stock sale................................ (97) - Accumulated deficit ...................................... (213,701) (202,534) Treasury stock, at cost, 165,883 and 105,989 shares at December 31, 2003 and 2004 respectively.................. (964) (549) Accumulated other comprehensive income..................... 364 3,068 ------------------ ------------------- Total stockholders' deficit................................... (72,203) (53,464) ------------------ ------------------- Total liabilities and stockholders' deficit................ $ 126,437 $ 152,685 ================== =================== See accompanying notes to consolidated financial statements
F-5
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31 ---------------------------------------------------------- 2002 2003 2004 ------------------- --------------------- ------------------ (In thousands except per share data) Revenues: Oil and gas production revenues ......................... $ 20,835 $ 29,710 $ 33,073 Rig revenues ............................................ 635 663 771 Other .................................................. 71 7 10 ----------------- --------------------- ------------------ 21,541 30,380 33,854 Operating costs and expenses: Lease operating and production taxes .................... 7,639 8,342 8,567 Depreciation, depletion, and amortization ............... 9,194 7,608 7,213 Proved property impairment .............................. 28,178 - - Rig operations .......................................... 567 609 671 General and administrative .............................. 4,045 3,995 5,126 Stock-based compensation................................. - 1,106 1,305 ----------------- --------------------- ---------------- 49,623 21,660 22,882 ----------------- --------------------- ---------------- Operating income (loss)..................................... (28,082) 8,720 10,972 Other (income) expense: Interest income ......................................... (92) (30) (10) Amortization of deferred financing fees ................. 1,325 1,630 1,848 Interest expense ........................................ 24,689 16,323 17,867 Financing costs.......................................... 967 4,406 1,657 Gain on debt redemption.................................. - - (12,561) Other ................................................... 201 100 387 ----------------- --------------------- ---------------- 27,090 22,429 9,188 ----------------- --------------------- ---------------- Income (loss) from continuing operations before cumulative effect of accounting change ............................. (55,172) (13,709) 1,784 Cumulative effect of accounting change...................... - 395 - ------------------ --------------------- --------------- Net income (loss) from continuing operations before income tax............................................ (55,172) (14,104) 1,784 ------------------ --------------------- --------------- Deferred income tax benefit.............................. - - (6,060) ------------------ --------------------- --------------- Income (loss) from continuing operations................. (55,172) (14,104) 7,844 Net income (loss) from discontinued operations........... (63,355) 70,024 3,323 ------------------ --------------------- --------------- Net income (loss) $ (118,527) $ 55,920 $ 11,167 =================- ===================== =============== Basic earnings (loss)per common share: Net earnings (loss) from continuing operations........ $ (1.84) $ (0.39) $ 0.22 Discontinued operations (loss)........................ (2.11) 1.98 0.09 Cumulative effect of accounting change................ - (0.01) - ------------------ --------------------- --------------- Net income (loss) per common share - basic .............. $ (3.95) $ 1.58 $ 0.31 =================- ===================== =============== Diluted earnings (loss) per common share: Net earnings (loss) from continuing operations........ $ (1.84) $ (0.39) $ 0.20 Discontinued operations (loss)........................ (2.11) 1.98 0.09 Cumulative effect of accounting change................ - (0.01) - ------------------ --------------------- --------------- Net income (loss) per common share - diluted............ $ (3.95) $ 1.58 $ 0.29 =================- ===================== =============== See accompanying notes to consolidated financial statements
F-6
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT (In thousands except number of shares) Accumulated Common Stock Treasury Stock Additional Other Receivable -------------------------------------- Paid-In Accumulated Comprehensive From Shares Amount Shares Amount Capital Deficit Income (Loss) Stock Sale Total ----------- --------------------------------------------------------------------------------------- Balance at December 31, 2001 30,145,280 $ 301 165,883 (964) $ 136,830 $ (151,094) (13,561) $(97) (28,585) Net loss................. - - - - - (118,527) - - (118,527) Hedge income......... - - - - - - 566 - 566 Foreign currency translation adjustment ........ - - - - - - 4,292 - 4,292 ----------- --------------------------------------------------------------------------------------- Balance at December 31, 2002 30,145,280 301 165,883 (964) 136,839 (269,621) (8,730) (97) 142,254) Net income.............. - - - - - 55,920 - - 55,920 Foreign currency translation adjustment ........ - - - - - - 9,067 - 9,067 Stock-base d compensation expense................ - - - - 1,106 - - - 1,106 Stock options exercised . 129,352 1 - - 84 - - - 85 Stock issued for acquisition of Wind River Resources........ 106,977 1 - - 91 - - - 92 Stock issued in connection with exchange offer......... 5,642,699 57 - - 3,724 - - - 3,781 ----------- --------------------------------------------------------------------------------------- Balance at December 31, 2003 36,024,308 360 165,883 (964) 141,835 (213,701) 364 (97) (72,203) Net income.............. - - - - 11,167 - - 11,167 Foreign currency translation adjustment ........ - - - - - 2,704 2,704 Proceeds from receivable - - - - - - 97 97 Stock issued for compensation........... 58,808 1 (59,894) 415 (87) - - - 329 Stock-based compensation expense................ - - - 1,305 - - - 1,305 Stock options and warrants exercised .... 513,929 - - 3,132 - - - 3,137 ----------- --------------------------------------------------------------------------------------- Balance at December 31, 2004 36,597,045 $360 105,989 $ (549) $ 146,185 $ (202,534) $ 3,068 $ - $(53,464) =========== ======================================================================================= See accompanying notes to consolidated financial statements.
F-7
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended December 31 ----------------------------------------------------------------------------- 2002 2003 2004 ----------------------------------------------------------------------------- (In thousands) Operating Activities Net income (loss) .................................. $ (118,527) $ 55,920 $ 11,167 Income (loss) from discontinued operations.......... (63,355) 70,024 3,323 ------------------ ----------------------- ------------------------- Income (loss) from continuing operations............ (55,172) (14,104) 7,844 Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization ............................... 9,194 7,608 7,213 Non-cash interest and financing cost........... - 16,422 5,967 Accretion of future site restoration........... - 379 108 Deferred tax benefit........................... - - (6,060) Proved property impairment .................... 28,178 - - Amortization of deferred financing fees........ 1,325 1,630 1,848 Stock-based compensation ...................... - 1,106 1,305 Changes in operating assets and liabilities: Accounts receivable ........................ 18,088 (7,850) 7,816 Equipment inventory ........................ 201 78 47 Other ..................................... 381 295 (338) Accounts payable ........................... (3) 2,161 990 Accrued expenses ........................... (44) 3,754 260 ------------------ ----------------------- ------------------------- Net cash provided by continuing operations......... 2,148 11,479 27,000 Net cash provided by (used in) discontinued operations.................................. (10,984) 16,125 3,265 ------------------ ----------------------- ------------------------- Net cash provided by (used in) operations........... (8,836) 27,604 30,265 ------------------ ----------------------- ------------------------- Investing Activities Capital expenditures, including purchases and development of properties ................... (5,070) (9,194) (9,269) Proceeds from sale of oil and gas properties....................................... 9,725 - - ------------------ ----------------------- ------------------------- Net cash (used in) provided by continuing operations 4,655 (9,194) (9,269) Net cash used in discontinued operations............ (9,691) 76,655 (12,069) ------------------ ----------------------- ------------------------- Net cash (used in) provided by investing activities. (5,036) 67,461 (21,338) Financing Activities Proceeds from issuance of common stock............ - - 3,465 Proceeds from long-term borrowings ............... - 43,051 147,955 Payments on long-term borrowings ................. (8,176) (131,283) (212,146) Deferred financing fees .......................... (1,516) (597) (5,056) Other............................................. - 177 98 ------------------ ----------------------- ------------------------- Net cash used in continuing operations............ (9,692) (88,652) (65,684) Net cash provided by (used in) discontinued operations..................................... 20,528 (6,970) 58,041 ------------------ ----------------------- ------------------------- Net cash (used in) provided by financing activities..................................... 10,836 (95,622) (7,643) ------------------ ----------------------- ------------------------- Increase (decrease) in cash ...................... (3,036) (4,389) 1,284 Cash at beginning of year ........................ 3,593 557 - ------------------ ----------------------- ------------------------- Cash at end of year............................... $ 557 $ - $ 1,284 ================== ======================= ========================= F-8 ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOW (CONTINUED) Years Ended December 31. ------------------------------------------------------------- 2002 2003 2004 ------------------ ---------------- ----------------- Supplemental disclosures of cash flow information: Interest paid .......................... $ 24,597 $ 3,637 $ 7,608 ================== ================ ================= See accompanying notes to consolidated financial statements.
F-9
ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) Years Ended December 31, --------------------------------------------------------- 2002 2003 2004 ------------------- ------------------ ------------------ (In thousands) Net income (loss)............................................ $ (118,527) $ 55,920 $ 11,167 Other Comprehensive income (loss): Hedging derivatives (net of tax) - See Note 4 - - 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.............. 4,292 4,632 - Effect of change in exchange rate........................... - 4,435 2,704 ------------------- ------------------ ------------------ Other comprehensive income (loss)................................ 4,858 9,067 - ------------------- ------------------ ------------------ Comprehensive income (loss)...................................... $ (113,669) $ 64,987 $ 13,871 =================== ================== ================== See accompanying notes to consolidated financial statements.
F-10 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 primarily engaged in the exploitation of 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 Wyoming. 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. As part of the series of transactions related to the Company's 2004 restructuring of operations, see Note 2, the Company approved a plan in 2004 to dispose of its operations and interest in Grey Wolf Exploration Inc. ("Grey Wolf") a wholly-owned Canadian subsidiary of Abraxas. In February 2005 Grey Wolf closed an initial public offering, resulting in our substantial divestiture of our capital stock and operations in Grey Wolf. As a result of the disposal of Grey Wolf, the results of operations of Grey Wolf are reflected in our Financial Statements as discontinued operations. See note 2. 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 hedges. 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. The Company maintains its cash and cash equivalents in excess of Federally insured limits in prominent financial institutioins considered by the Company to be of high credit quality. 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 $11,000 at December 31, 2003 and 2004. 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-11 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 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. 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, which limit the impact of price reductions 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. In 2003, the Company elected out of hedge accounting as prescribed by SFAS 133. Accordingly all derivatives will be recorded on the balance sheet at fair value with changes in fair value being 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-12 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. 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 and $1.3 million during 2003 and 2004 respectively. There was no stock based compensation expense for the year ended December 31, 2002. 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 2002, 2003 and 2004, risk-free interest rates of 1.5% each year; 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 ----------------------------------------------------------------- 2002 2003 2004 ------------------ ----------------- ---------------- Net income (loss) as reported (including discontinued operations $ (118,527) $ 55,920 $ 11,167 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects - 1,106 1,305 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (670) (228) (112) ------------------ ----------------- ---------------- Pro forma net income (loss) $ (119,197) $ 56,798 $ 12,360 ================== ================= ================ Earnings (loss) per share: Basic - as reported $ (3.95) $ 1.58 $ 0.31 ================== ================= ================ Basic - pro forma $ (3.98) $ 1.61 $ 0.34 ================== ================= ================ Diluted - as reported $ (3.95) $ 1.58 $ 0.29 ================== ================= ================ Diluted - pro forma $ (3.98) $ 1.61 $ 0.32 ================== ================= ================
Foreign Currency Translation The functional currency for Grey Wolf is the Canadian dollar ($CDN). The Company translates the functional currency into U.S. dollars ($US) based on the current exchange rate at the end of the period for the balance sheet and a weighted average rate for the period on the statement of operations. Translation adjustments are reflected as accumulated other comprehensive income (loss) in the consolidated financial statement of stockholders' deficit. The amount reflected in the accompanying financial statements relates to discontinued operations. F-13 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. 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. 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. The following table summarizes the Company's asset retirement obligation transactions related to continuing operations during the following years:
2003 2004 ----------------- -------------------- Beginning asset retirement obligation............. $ - $ 776 Additions related to new properties............... 973 132 Deletions related to property disposals........... (576) (128) Accretion expense................................. 379 108 ----------------- -------------------- Ending asset retirement obligation................ $ 776 $ 888 ================= ====================
Revenue Recognition and Major Customers 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, 2004. During 2002, 2003 and 2004 sales to two customers accounted for approximately 77%, 80% and 64% of crude oil and natural gas revenues. Deferred Financing Fees Deferred financing fees are being amortized on a level yield basis over the term of the related debt arrangements. F-14 Assets and Liabilities Held for Sale The Company holds assets and liabilities related to discontinued operations as held for sale, in accordance with Statement of Financial Standards No. 144 "Accounting for Impairment of Disposal of Long-Lived Assets" (SFAS 144). The Company records its assets at the lower of its carrying amount or fair market value less cost to sell and does not depreciate or amortize the assets while classified as held for sale. 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. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be realized. New Accounting Pronouncements In September 2004, the Securities and Exchange Commission issued "Staff Accounting Bulletin No. 106" (SAB No. 106). SAB No. 106 applies to companies using the full cost method of accounting for oil and gas properties and equipment costs. SAB No. 106 affects the way in which companies calculate their full cost ceiling limitation (including asset retirement cost related to proved developed properties in the calculation of the ceiling) and the way companies calculate depletion on oil and gas properties (only asset retirement cost for new recompletions and new wells will be included in future development costs in calculating depletion rates). The Company does not anticipate that adoption of SAB No 106 will have a significant impact on its financial position or results of operations. In November 2004, the FASB issued SFAS No. 151, entitled " Inventory Costs- an amendment of ARB 43, chapter. The purpose of this statement is to clarify the accounting for abnormal amounts of idle facilities expense, freight, handling cost and wasted material. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is evaluating the effect of this statement on it's operations and does not expect it to impact it's financial statements. In December 2004 the FASB issued "Summary of Statement No. 123 (revised 2004), Share-Based Payment. This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for: (1) equity instruments of the enterprise or (2) liabilities that are based on the fair value of the enterprise's equity instruments or that may be settled by the issuance of such equity instruments. The proposed statement would eliminate the ability to account for share-based compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued to Employees" and generally would require instead that such transactions be accounted for using a fair value-based method. As proposed, this statement is be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company is currently evaluating what effect this statement will have on the Company's financial position or results of operations. In December 2004 the FASB issued FASB No. 153, entitled " Exchanges of Nonmonetary Assets - an amendment of ABP Opinion No. 29". The guidance in ABP Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that Opinion, however, included certain exceptions to that principle. This statement amends Opinion 29 to eliminate the exception for nonmonetary of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The statement is effective for nonmonetary exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not anticipate this statement impacting its financial statements. 2. Discontinued Operations and Subsequent Events As part of the restructuring operations in 2004 - see Note 3, the Company approved a plan to dispose of its operations and interest in Grey Wolf. On February 28, 2005, Abraxas substantially divested its investment in Grey Wolf. Pursuant to an Underwriting Agreement, the underwriters purchased 17,800,000 common shares of Grey Wolf capital stock from Grey Wolf (the "Treasury Shares"), and 9,100,000 shares of Grey Wolf common stock owned by Abraxas (the "Secondary Shares") from Abraxas at a purchase price of CDN $2.80 per share. F-15 Abraxas also granted to the underwriters an over-allotment option to purchase from Abraxas, at the underwriters' election, up to an additional 3,902,360 shares of Grey Wolf common stock held by Abraxas (the "Option Shares"). The over-allotment option may be exercised in whole or in part at any one time prior to thirty calendar days after the closing date for the IPO. Grey Wolf utilized the proceeds from the sale of the Treasury Shares to re-pay and terminate its $35 million term loan and re-pay $1 million in inter-company debt to Abraxas. Abraxas utilized the $1 million received from Grey Wolf and the proceeds received from the sale of the Secondary Shares to re-pay outstanding debt under its $25 million bridge loan. After consummation of the offering, Abraxas' remaining debt under the bridge loan was $5.4 million - see Note 3. As part of the approved 2004 disposal plan, the Company's will divest the remaining 3,902,360 shares of Grey Wolf common stock, utilizing the proceeds to retire the balance of the bridge loan. On March 24, 2005, the Company was advised of the underwriter's intent to exercise 3.5 million of the over allotment shares. Closing for this exercise is scheduled for March 31 and will provide approximately $7.5 million that Abraxas will utilize to payoff the remaining balance of its Bridge Loan. The remaining proceeds of approximately $2 million will be used to pay down the Company's revolving credit facility to, effectively, zero. The operations of Grey Wolf, previously reported as a business segment, are reported as discontinued operations for all periods presented in the accompanying financial statements and the operating results are reflected separately from the results of continuing operations. Interest attributable to discontinued operations represents interest on debt attributable to the Canadian subsidiary, no general allocation of Abraxas interest was attributed to Grey Wolf in prior periods. Summarized discontinued operations operating results and net gain (loss) for the years ended December 31, 2002, 2003 and 2004 were:
Years ended December 31, ------------------------------------------------------------ 2002 2003 2004 ---------------- ----------------- ------------------ (in thousands) Total revenue........................................ $ 32,779 $ 8,639 $ 15,082 Income (loss) from operations before income tax...... (93,052) 70,401 3,323 Income tax expense (benefit)......................... (29,697) 377 - ---------------- ----------------- ------------------ Income (loss) from discontinued operations........... $ (63,355) $ 70,024(1) $ 3,323 ================ ================= ==================
(1) In 2003, as part of a series of transactions related to a financial restructuring including an exchange offer, redemption of certain notes payable and a credit agreement, the Company sold its wholly owned Canadian subsidiaries. The 2003 statement of operations includes a gain on the sale of the Canadian subsidiaries in January 2003 of $68.9 million. Assets and liabilities of discontinued operations were as follows:
December 31, ---------------------------------- 2003 2004 -------------- -------------- (in thousands) Assets: Cash...................................................................... $ 493 $ 693 Accounts receivable....................................................... 903 2,556 Net property.............................................................. 35,542 45,426 Deferred financing fees................................................... - 3,577 Other..................................................................... 154 348 -------------- -------------- $ 37,092 $ 52,600 ============== ============== Liabilities: Accounts payable and accrued expenses..................................... $ 1,971 $ 5,262 Long-term debt (1)........................................................ - 60,000 Other..................................................................... 601 1,685 -------------- -------------- $ 2,572 $ 66,947 ============== ==============
(1) Includes Abraxas Bridge Loan of $25 million and $35 million related to Grey Wolf term loan. F-16 3. Restructuring Transactions On October 28, 2004, in order to provide the Company with greater flexibility in conducting its business, including increasing capital spending and exploiting its additional drilling opportunities, Abraxas refinanced all of its then existing indebtedness by redeeming its 11 1/2% secured notes due 2007 and terminating its previous credit facility with the net proceeds from: o the private issuance of $125.0 million aggregate principal amount of the Floating Rate Senior Secured Notes due 2009, Series A; o the proceeds of its new $25.0 million second lien increasing rate bridge loan; and o the payment to Abraxas by Grey Wolf of $35.0 million from the proceeds of Grey Wolf's new $35.0 million term loan. As a part of the refinancing, the Company also entered into a new $15.0 million revolving credit facility, which currently has availability of approximately $13.0 million. In connection with the redemption of the previous secured notes, the Company recognized a $12.6 million gain on extinguishment in 2004. Also in connection with the restructuring of operations in late 2004, the Company approved a plan to dispose of its operations and interest in Grey Wolf. In connection with the Grey Wolf IPO completed in February 2005, net proceeds of approximately $37 million from the offering by Grey Wolf of treasury shares were used to repay Grey Wolf's term loan in its entirety and eliminate its working capital deficit. Net proceeds of approximately $20 million from the secondary shares offered by Abraxas were used to reduce the amount outstanding under its bridge loan to approximately $5.4 million. On March 24, 2005, the Company was advised of the underwriter's intent to exercise 3.5 million of the over allotment shares. See Note 2. Floating Rate Senior Secured Notes due 2009. In connection with the October 2004 financial restructuring, Abraxas issued $125 million in principal aggregate amount of Floating Rate Senior Secured Notes due 2009. The new notes will mature on December 1, 2009 and began accruing interest from the date of issuance, October 28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The initial interest rate on the new notes is 9.72% per annum. The interest will be reset semi-annually on each June 1 and December 1, commencing on June 1, 2005. Interest is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on June 1, 2005. Abraxas' New $15 Million Senior Secured Revolving Credit Facility. On October 28, 2004, Abraxas entered into an agreement for a new revolving credit facility having a maximum commitment of $15 million, which includes a $2.5 million subfacility for letters of credit. Availability under the new revolving credit facility is subject to a borrowing base consistent with normal and customary natural gas and crude oil lending transactions. Outstanding amounts under the new revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, National Association plus 1.00%. Subject to earlier termination rights and events of default, the stated maturity date under the new revolving credit facility is October 28, 2008. Abraxas' New $25 Million Second Lien Increasing Rate Bridge Loan. On October 28, 2004, Abraxas borrowed $25 million under its new bridge loan. The balance of the Bridge Loan ($25 million) and the Grey Wolf Term loan ($35 million) as of December 31, 2004 are included in liabilities related to assets held for sale. 4. Long-Term Debt As described in Note 3, the 11 1/2% Secured Notes and the Senior Credit Agreement were refinanced in October 2004. The following is a brief description of the Company's debt as of December 31, 2003 and 2004, respectively: F-17
December 31 -------------------------------- 2003 2004 -------------------------------- (in thousands) 11.5% Secured Notes due 2007 ...................................... $ 137,258 $ - Senior Credit Agreement ........................................... 47,391 - Floating rate senior secured notes due 2009........................ - 125,000 Senior secured revolving credit facility........................... - 1,425 -------------------------------- 184,649 126,425 Less current maturities ........................................... - - -------------------------------- $ 184,649 $ 126,425 ================================
Floating Rate Senior Secured Notes due 2009. In connection with the October 2004 financial restructuring, Abraxas issued $125 million in principal aggregate amount of Floating Rate Senior Secured Notes due 2009. The notes were issued under an indenture with U.S. Bank National Association. Abraxas' New $15 Million Senior Secured Revolving Credit Facility. On October 28, 2004, Abraxas entered into an agreement for a new revolving credit facility having a maximum commitment of $15 million, which includes a $2.5 million subfacility for letters of credit. Availability under the new revolving credit facility is subject to a borrowing base consistent with normal and customary natural gas and crude oil lending transactions. Outstanding amounts under the new revolving credit facility bear interest at the prime rate announced by Wells Fargo Bank, National Association plus 1.00%. Subject to earlier termination rights and events of default, the stated maturity date under the new revolving credit facility is October 28, 2008. Abraxas' New $25 Million Second Lien Increasing Rate Bridge Loan. On October 28, 2004, Abraxas borrowed $25 million under its new $25 million bridge loan. Interest on the bridge loan currently accrues at a rate of 12.0% per annum until October 28, 2005, and is payable monthly in cash. Interest on the bridge loan will thereafter accrue at a rate of 15.0% per annum, and will be payable in-kind. Subject to earlier termination rights and events of default, the stated maturity date under the bridge loan is October 28, 2010. The bridge loan balance of $25 million is included in liabilities related to assets held for sale. See note 2. The new revolving credit facility, bridge loan and indenture governing the notes contain certain restrictions and covenants that, among other things, limit the Company's ability to incur additional indebtedness, transfer or sell assets, guarantee debt, and other items. Additionally, the Company must comply with certain financial covenants and satisfy financial condition tests. The Company was in compliance with the covenants at December 31, 2004. The following table represents the maturities of our long-term debt: Year ending December 31, Amount 2005 - 2006 - 2007 - 2008 $1,425 2009 $ 125,000 ------------- $ 126,425 ============= 5. Property and Equipment The major components of property and equipment, at cost, are as follows:
Estimated December 31 ---------------------------------- Useful Life 2003 2004 ----------------- ---------------- ----------------- Years (In thousands) Crude oil and natural gas properties ........... - $ 288,559 $ 297,647 F-18 Equipment and other ............................ 7 2,749 2,930 ---------------- ----------------- $ $ 291,308 $ $ 300,577 ================ =================
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 expired in November 2004. 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. The Company has not purchased any shares of its common stock for treasury stock in subsequent years. 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. The Company's 1994 Long-Term Incentive Plan has authorized the grant of options to management, employees and directors for up to approximately 6.1 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, 2004 approximately 2.6 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:
2002 2003 2004 ----------------------------- ----------------------------- ----------------------------- Options Weighted-Average Options Weighted-Average Options Weighted-Average (000s) Exercise Price (000s) Exercise Price (000s) Exercise Price ---------- ------------------ ---------- ------------------ --------- ------------------ Outstanding-beginning of year ................... 4,942 $ 3.28 3,305 $ 1.85 3,364 $ 0.90 Granted ................... 521 0.68 360 0.68 - - Exercised ................. - - (129) 0.66 (414) 0.69 Forfeited/Expired ......... (2,158) 4.84 (172) 1.61 (57) 0.77 ---------- ---------- --------- Outstanding-end of year ... 3,305 $ 1.85 3,364 $ 0.90 2,893 $ 0.93 ========== ========== ========= Exercisable at end of year 2,136 $ 1.91 2,331 $ 0.95 2,327 $ 0.97 ========== ========== ========= Weighted-average fair value of options granted during the year $ 0.63 $ 0.38 $ 0.00
F-19 The following table represents the range of option prices and the weighted average remaining life of outstanding options as of December 31, 2004:
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 2,294,719 5.1 $ 0.69 1,818,472 $ 0.70 $ 1.01 - 1.63 257,500 6.8 1.22 176,875 1.31 $ 2.06 - 2.21 311,358 2.3 2.07 309,269 2.07 $ 4.83 30,001 6.2 4.83 22,501 4.83
In January 2003, in connection with the financial restructuring, 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 plan 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 2002, 2003 or 2004. 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 2002, 2003 or 2004. 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 had a four-year term beginning July 1, 2000. and expired on June 30, 2004. In October 2004, the Company issued 1.1 million warrants in conjunction with the refinancing. Each is exercisable for one share of common stock at an exercise price of $0.01 per share. These warrants have a ten year term. At December 31, 2004, the Company has approximately 4.0 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 --------------------------- 2003 2004 ------------- ------------- (In thousands) Deferred tax liabilities: U.S. full cost pool ..................................................... $ 4,835 $ 7,310 ------------- ------------- Total deferred tax liabilities ............................................ 4,835 7,310 Deferred tax assets: Capital loss carryforward................................................ 12,895 11,913 F-20 Original issue discount on certain debt obligations...................... 22,453 - Depletion ............................................................... 4,856 3,232 Net operating losses ("NOL")............................................ 35,218 64,408 Investment in foreign subsidiaries....................................... - 2,426 Other ................................................................... 2,575 4,432 ------------- ------------- Total deferred tax assets ................................................. 77,997 86,366 Valuation allowance for deferred tax assets ............................... (73,162) (72,996) ------------- ------------- Net deferred tax assets ................................................... 4,835 13,370 ------------- ------------- Net deferred tax liabilities (assets) ..................................... $ - $ (6,060) ============= =============
Significant components of the provision (benefit) for income taxes are as follows:
2002 2003 2004 ----------------------------------------- (in thousands) Current: Federal.......................................................... $ - $ - $ - Foreign ......................................................... - - - ----------------------------------------- $ - $ - $ - ========================================= Deferred: Federal ......................................................... $ - $ - $ 6,060 Foreign ......................................................... 29,697 377 - ----------------------------------------- 29,697 377 6,060 Attributable to discontinued operations.......................... (29,697) (377) - ----------------------------------------- Attributable to continuing operations............................ $ - $ - $ 6,060 =========================================
At December 31, 2004 the Company had, subject to the limitation discussed below, $184 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2004 through 2022 if not utilized. 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 $73.2 million and $73.0 million for deferred tax assets at December 31, 2003 and 2004, respectively. The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is:
December 31 --------------------------------------------------------------------- 2002 2003 2004 -------------------------------------------- ------------------------ (in thousands) Tax (expense) benefit at U.S. statutory rates (35%) ............................ $ 51,878 $ (19,842) $ (1,875) (Increase) decrease in deferred tax asset valuation allowance .................... (59,456) 22,993 8,123 Write-down of non-tax basis assets...... (7,009) - - Higher effective rate of foreign 7,349 (2,835) (140) operations............................ Percentage depletion ................... 683 - - Investment in foreign subsidiaries .... 35,604 - - Other .................................. 648 (693) (48) --------------------- ----------------------- ------------------------ $ 29,697 $ (377) $ 6,060 Attributable to discontinued operations (29,697) 377 - --------------------- ----------------------- ------------------------ Attributable to continuing operations.. $ - $ - $ 6,060 ===================== ======================= ========================
9. Related Party Transactions Accounts receivable - Other includes approximately $35,558 and $0 as of December 31, 2003 and 2004, respectively, representing amounts due from officers relating to advances made to employees. F-210 10. Commitments and Contingencies Operating Leases During the years ended December 31, 2002, 2003 and 2004 the Company incurred rent expense related to leasing office facilities of approximately $236,000, $246,650 and $256,355 respectively. Future minimum rental payments are as follows at December 31, 2004. 2005............................................. $ 254,004 2006............................................. 83,908 Thereafter....................................... - ------------------ $ 337,912 ================== Litigation and Contingencies In 2001, the Company and a limited partnership, of which Wamsutter Holdings, Inc. is the general partner (the "Partnership"), were named in a lawsuit filed in U.S. District Court in the District of Wyoming. The claim asserted breach of contract, fraud and negligent misrepresentation by the Company and the Partnership related to the responsibility for year 2000 ad valorem taxes on crude oil and natural gas properties sold by the Company and the Partnership. In February 2002, a summary judgment was granted to the plaintiff in this matter and a final judgment in the amount of $1.3 million was entered. The Company and the Partnership appealed the District Court's judgment and on November 3, 2004, the U.S. Court of Appeals for the 10th Circuit affirmed the District Court's decision. On December 14, 2004, the U.S. Court of Appeals for the 10th Circuit entered a mandate for the District Court to enforce the judgment. As of December 27, 2004, the final judgment amount was approximately $1.55 million (which includes accrued and unpaid interest since February 2002). The Company has decided not to pursue further appeals and subsequent to December 31, 2004, paid its portion of the final judgment, approximately $1 million, for which the Company had previously established a reserve. 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, 2004 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:
2002 2003 2004 -------------------------------------------------------- Numerator: Net income (loss) before effect of discontinued operations and accounting change .............. $ (55,172,000) $ (14,104,000) $ 7,844,000 Discontinued operations........................... (63,355,000) 70,024,000 3,323,000 Cumulative effect of accounting change........... - (395,000) - -------------------------------------------------------- $(118,527,000) 55,920,000 11,167,000 Denominator: Denominator for basic earnings per share - weighted-average shares ........................ 29,979,397 35,364,363 36,221,887 Effect of dilutive securities: Stock options and warrants..................... - - 2,672,778 -------------------------------------------------------- F-22 Dilutive potential common shares Denominator for diluted earnings per share - adjusted weighted-average shares and assumed exercise of options and warrants................ 29,979,397 35,364,363 38,894,665 ======================================================== Basic earnings (loss) per share: Net income (loss) before effect of discontinued operations and accounting change.................. $ (1.84) $ (0.39) $ 0.22 Discontinued operations (2.11) 1.98 0.09 Cumulative effect of accounting change.......... - (0.01) - -------------------------------------------------------- Net income (loss) per common share................ $ (3.95) $ 1.58 $ 0.31 ======================================================== Diluted earnings (loss) per share: Net income (loss) before effect of discontinued operations and accounting change.................e $ (1.84) $ (0.39) $ 0.20 Discontinued operations........................... (2.11) 1.98 0.09 Cumulative effect of accounting change.......... - (0.01) - -------------------------------------------------------- Net income (loss) per common share - diluted. $ (3.95) $ 1.58 $ 0.29 ========================================================
For the year ended December 31, 2002, and 2003 5.9 million and 711,000 shares 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, 2003 and 2004 are as follows:
1st 2nd 3rd 4th Quarter Quarter Quarter Quarter ---------------- ---------------- --------------- ---------------- (In thousands, except per share data) Year Ended December 31, 2003 Net revenue - as previously reported.. $ 13,111 $ 8,430 $ 8,430 $ 9,048 Net revenue - discontinued operations. (4,312) (1,212) (1,254) (1,861) ---------------- ---------------- --------------- ---------------- Net revenue - continuing operations... 8,799 7,218 7,176 7,187 Operating income (loss) - as previously reported................. 5,646 1,927 2,694 1,275 Operating income (loss) - discontinued operations............. (2,243) (288) (279) (12) ---------------- ---------------- --------------- ---------------- Operating income (loss) - continuing operations.......................... 3,403 1,639 2,415 1,263 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) Year Ended December 31, 2004 Net revenue - as previously reported.. $ 10,935 $ 12,267 $ 11,783 $ 13,951 Net revenue - discontinued operations. (2,975) (3,763) (3,546) (4,798) ---------------- ---------------- --------------- ---------------- Net revenue - continuing operations... 7,960 8,504 8,237 9,153 Operating income (loss) as previously reported............................ 983 5,707 3,202 6,342 Operating income (loss) - discontinued operations............. (407) (860) (1,365) (2,140) ---------------- ---------------- --------------- ---------------- Operating income (loss) continuing operations.......................... 576 4,847 1,837 3,712 Net income (loss)..................... (5,557) 372 (1,643) 17,995 Net income (loss) per common share - basic............................... $ (0.15) $ 0.01 $ (0.05) $ 0.50 Net income (loss) per common share - diluted............................. $ (0.15) $ 0.01 $ (0.05) $ 0.47
F-23 13. Benefit Plans The Company has a defined contribution plan (401(k)) covering all eligible employees of the Company. The Company matched employee contributions in 2004. 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 $12,000 in 2003 and $13,000 in 2004. The contribution limit for 2004 was $16,000 for employees 50 years of age or older. 14. 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. In 2003 the Company elected out of hedge accounting as prescribed by SFAS 133. Accordingly, instruments are recorded on the balance sheet at their fair value with adjustments to the carrying value of the instruments bring recognized in oil and gas income in the current period. Under the terms of the Company's revolving credit facility, 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. As of December 31, 2004 the Company's hedging positions were as follows:
Time Period Notional Quantities Price ---------------------------------- -------------------------------------------- ---------------------- January 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 February 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 March 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 April 2005 7,100 MMbtu of production per day Floor of $4.50 400 Bbls of crude oil production per day Floor of $25.00 May - December 2005 9,500 MMbtu of production per day Floor of $5.00
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. 15. 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. During the second quarter of 2002, the Company had a ceiling limitation write-down of approximately $28.2 million related to continuing operations. At December 31, 2003 and 2004, the net capitalized cost of crude oil and natural gas properties, plus the cost of properties not being amortized and the lower of cost of fair value of unproved properties being included in cost being amortized, less related income taxes did not exceed the present value of our estimated reserves, as such, no write-down was recorded. F-24 16. Supplemental Oil and Gas Disclosures (Unaudited) The accompanying table presents information concerning the Company's crude oil and natural gas producing activities from continuing operations 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 from continuing operations are as follows: Years Ended December 31, 2003 2004 ---------------- --------------- (In thousands) Proved crude oil and natural gas properties ... $ 288,559 $ 297,647 Unproved properties ........ - - ---------------- --------------- Total..................... 288,559 297,647 Accumulated depreciation, depletion, and amortization, and impairment ............... (212,609) (219,726) ---------------- --------------- Net capitalized costs .. $ 75,950 $ 77,921 ================ =============== Cost incurred in oil and gas property acquisitions and development activities related to continuing operations are as follows: Years Ended December 31, ------------------------------------------- 2002 2003 2004 -------------- -------------- ------------- (In Thousands) ------------------------------------------- Property acquisition costs: Proved ...................... $ - $ - $ - Unproved .................... - - - -------------- -------------- ------------- $ - $ - $ - ============== ============== ============= Property development and exploration costs ........... $ 4,944 $ 9,158 $ 9,088 ============== ============== ============= The results of operations for oil and gas producing activities from continuing operations for the three years ending December 31, 2002, 2003 and 2004, respectively are as follows: Years Ended December 31, ------------------------------------------- 2002 2003 2004 -------------- ------------- ------------- (In thousands) Revenues ................... $ 20,835 $ 29,710 $ 33,073 Production costs ........... (7,639) (8,342) (8,567) Depreciation, depletion, and amortization ......... (8,879) (7,428) (7,117) Proved property impairment . (28,178) - - General and administrative . (1,011) (998) (1,281) -------------- ------------- ------------- Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) .......... $ (24,872) $ 12,942 $ 16,108 ============== ============= ============= Depletion rate per barrel of oil equivalent, before impact of impairment ..... $ 7.55 $ 7.24 $ 7.39 ============== ============= ============= F-25 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, 2002, 2003, and 2004 related to continuing operations. 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.
Liquid Natural Hydrocarbons Gas ------------------ -------------- (Barrels) (Mcf) (In thousands) Proved developed and undeveloped reserves: Balance at December 31, 2001...................... 4,407 108,468 Revisions of previous estimates ................ (64) (14,986) Production ..................................... (264) (5,733) Sale of minerals in place ...................... (843) (9,553) ------------------ -------------- Balance at December 31, 2002 ..................... 3,236 78,196 Revisions of previous estimates ................ 268 6,759 Extensions and discoveries ..................... 44 28 Production ..................................... (229) (4,781) ------------------ -------------- Balance at December 31, 2003...................... 3,319 80,202 Revisions of previous estimates ................ (60) (754) Extensions and discoveries ..................... 70 73 Production ..................................... (229) (4,403) ------------------ -------------- Balance at December 31, 2004...................... 3,101 75,118 ================== ============== Liquid Natural Hydrocarbons Gas ------------------ -------------- (Barrels) (Mcf) Proved developed reserves: December 31, 2002 ................................ 1,754 34,776 ================== ============== December 31, 2003................................. 1,887 39,371 ================== ============== December 31, 2004................................. 1,878 36,241 ================== ==============
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, 2004 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 F-26 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. Set forth below is the Standardized Measure relating to proved oil and gas reserves relating to continuing operations for the three years ending December 31, 2002, 2003 and 2004.
Years Ended December 31, ------------------------------------------------------ 2002 2003 2004 ------------------------------------------------------ (in Thousands) Future cash inflows ... $ 389,061 $ 512,797 $ 498,165 Future production and development costs ... (158,507) (179,036) (194,187) Future income tax expense ............. - - - ------------------------------------------------------ Future net cash flows . 230,554 333,761 303,978 Discount .............. (120,238) (172,177) (154,943) ------------------------------------------------------ Standardized Measure of discounted future net cash relating to proved reserves ..... $ 110,316 $ 161,584 $ 149,035 ======================================================
F-27 F-29 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 related to continuing operations:
Year Ended December 31 ---------------------------------------------------------- 2002 2003 2004 ------------------- ------------------- ------------------ (In thousands) Standardized Measure, beginning of year ................................. $ 77,187 $ 110,316 $ 161,584 Sales and transfers of oil and gas produced, net of production costs ....... (13,196) (21,368) (24,506) Net changes in prices and development and production costs from prior year .... 56,447 42,398 (2,814) Extensions, discoveries, and improved recovery, less related costs ............ - 471 810 Purchase of minerals in place.............. - 313 - Sales of minerals in place ................ (9,089) - - Revision of previous quantity estimates ... (9,581) 9,351 (1,818) Other ..................................... 829 9,071 (380) Accretion of discount ..................... 7,719 11,032 16,159 ------------------- ------------------- ------------------ Standardized Measure, end of year ....... $ 110,316 $ 161,584 $ 149,035 =================== =================== ==================
F-28 17. Restatement - Year Ended December 31, 2002 In January 2003, the Company sold its wholly-owned Canadian subsidiaries as part of a series of transactions related to a financial restructuring. Subsequent to the original 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, in July 2003 the consolidated statements of operations and cash flows for the year ended December 31, 2002 were restated to present results of operations and cash flows as components of continuing operations. As discussed in Note 2, during 2004 the business segment containing the Grey Wolf operations was discontinued. A summary of the significant effects of the restatement and subsequent discontinued operations is as follows:
For the Year Ended December 31, 2002 ------------------------------------------------ As As Restated As Reported Originally Reported Herein -------------- ------------- -------------- (in thousands) Revenues: Oil and gas production revenue................ $21,601 $ 50,862 $ 20,835 Gas processing revenue....................... - 2,420 - Rig revenue.................................. 635 635 635 Other........................................ 71 403 71 -------------- ------------- -------------- 22,307 54,320 21,541 Operating costs and expenses: Lease operating and production taxes......... 7,910 15,240 7,639 Depreciation, depletion and amortization..... 9,654 26,539 9,194 Proved property impairment................... 32,850 115,993 28,178 Rig operations............................... 567 567 567 General and administrative................... 5,082 6,884 4,045 Stock-based compensation..................... - - - -------------- ------------- -------------- 56,063 165,223 49,623 -------------- ------------- -------------- Operating loss.................................. (33,756) (110,903) (28,082) Other (income) expense: Interest income.............................. (92) (92) (92) Amortization of deferred financing fees...... 1,325 2,095 1,325 Interest expense............................. 24,689 34,150 24,689 Financing costs.............................. 967 967 967 (Gain) loss on sale of equity investment..... - - - Other........................................ 201 201 201 -------------- ------------- -------------- 27,090 37,321 27,090 -------------- ------------- -------------- Income loss before income tax.................. (60,846) (148,224) (55,172) Income tax expense (benefit): Current...................................... - - - Deferred..................................... - (29,697) - Loss from discontinued operations............... (57,681) - (63,355) -------------- ------------- -------------- Net loss........................................ $(118,527) $(118,527) $ (118,527) ============== ============= ==============
F-29