10-KT 1 d85558e10-kt.txt TRANSITION REPORT FOR PERIOD 7/1/00 TO 12/31/00 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED _______ OR [X] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM JULY 1, 2000 TO DECEMBER 31, 2000 COMMISSION FILE NUMBER 0-21179 DEVX ENERGY, INC. DEVX ENERGY, INC. DEVX OPERATING COMPANY CORRIDA RESOURCES, INC. (EXACT NAME OF REGISTRANTS AS SPECIFIED IN THEIR CHARTER) DELAWARE 75-2615565 NEVADA 75-2564071 NEVADA 75-2593510 NEVADA 75-2691594 (STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER INCORPORATION OR ORGANIZATION) IDENTIFICATION NOS.) 13760 NOEL RD., SUITE 1030 DALLAS, TEXAS 75240-7336 (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) (REGISTRANTS' TELEPHONE NUMBER, INCLUDING AREA CODE) (972) 233-9906 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: COMMON STOCK, PAR VALUE $0.234 PER SHARE (TITLE OF CLASS) ---------- 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 REGISTRANTS' KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT OF THIS FORM 10-K. [ ] STATE THE AGGREGATE MARKET VALUE OF THE VOTING AND NON-VOTING COMMON EQUITY HELD BY NON-AFFILIATES (ALL DIRECTORS AND OFFICERS ARE PRESUMED TO BE AFFILIATES FOR THIS CALCULATION) OF THE REGISTRANT ON MARCH 16, 2001, WAS $106,280,467 BASED ON THE CLOSING PRICE PER SHARE OF THE COMMON STOCK ON SUCH DATE. THE NUMBER OF SHARES OF COMMON STOCK, PAR VALUE $0.234 PER SHARE, OF REGISTRANT OUTSTANDING ON MARCH 15, 2001 WAS 12,748,612. DOCUMENTS INCORPORATED BY REFERENCE PORTIONS OF THE REGISTRANT'S PROXY STATEMENT FOR THE 2001 ANNUAL MEETING OF STOCKHOLDERS, EXPECTED TO BE FILED ON OR PRIOR TO APRIL 30, 2001, ARE INCORPORATED BY REFERENCE INTO PART III. ================================================================================ 2 TABLE OF CONTENTS

PAGE ---- PART I................................................................................................1 Item 1. Business...................................................................2 Item 2. Description of Properties.................................................22 Item 3. Legal Proceedings.........................................................22 Item 4. Submission of Matters to a Vote of Security Holders.......................22 PART II..............................................................................................23 Item 5. Market for the Common Stock and Related Stockholder Matters...............23 Item 6. Selected Financial Data...................................................25 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.....................................................26 Item 7A. Quantitative and Qualitative Disclosures About Market Risk................35 Item 8. Financial Statements and Supplementary Data...............................36 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................................................36 PART III.............................................................................................37 Item 10. Directors and Executive Officers of the Registrant........................37 Item 11. Executive Compensation....................................................37 Item 12. Security Ownership of Certain Beneficial Owners and Management............37 Item 13. Certain Relationships and Related Transactions............................37 PART IV..............................................................................................41 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...........41 SIGNATURE PAGE.......................................................................................45 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS..........................................................F-1

3 DEVX ENERGY, INC. PART I A WARNING ABOUT FORWARD-LOOKING STATEMENTS We have made forward-looking statements in this Annual Report on Form 10-K that are subject to risks and uncertainties. These forward-looking statements include information about possible or assumed future results of our operations. Also, when we use any of the words "believes," "expects," "intends," "anticipates" or similar expressions, we are making forward-looking statements. Examples of types of forward-looking statements include statements on: o our oil and natural gas reserves; o future acquisitions; o future drilling and operations; o future capital expenditures; o future production of oil and natural gas; and o future net cash flow. You should understand that the following important factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K, could affect our future financial results and performance and cause our results or performance to differ materially from those expressed in our forward-looking statements: o the timing and extent of changes in prices for oil and natural gas; o the need to acquire, develop and replace reserves; o our ability to obtain financing to fund our business strategy; o environmental risks; o drilling and operating risks; o risks related to exploitation and development projects; o competition; o government regulation; and o our ability to meet our stated business goals. We claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995 for these statements. You should consider these risks when you purchase our common stock and the risks discussed in "Item 1. Business -- Risk Factors." SUBSIDIARY REGISTRANTS Due to requirements of the Securities and Exchange Commission, certain subsidiaries of the parent company are also shown as co-registrants on this Annual Report on Form 10-K. Unless otherwise stated, the information provided in the Form 10-K describes the business, assets, financial condition and financial results of the parent company and the consolidated subsidiaries as if they were one entity. As used herein, references to "DevX Energy, Inc.," "us" or "we" are to DevX Energy, Inc., a Delaware corporation, and its consolidated subsidiaries. 1 4 ITEM 1. BUSINESS GENERAL THE COMPANY We are an independent energy company engaged in the exploration, development, exploitation and acquisition of oil and natural gas properties in conventional producing areas of North America. To date, we have grown almost exclusively through acquisitions of properties and development drilling. As a result of our acquisitions, we own a diverse property base concentrated in six producing areas or basins. Approximately one-half of our proved reserves are concentrated in south and east Texas. Our assets are primarily long-lived natural gas properties exhibiting low operating costs. At December 31, 2000, we owned proved reserves of approximately 130 Bcf of natural gas and 1.4 MMBbls of oil aggregating to approximately 138 Bcfe with an SEC PV-10 value of $534 million and a reserve life index of 12.4 years. Approximately 67% of our proved reserves were classified as proved developed and approximately 94% of our proved reserves were natural gas. Our average daily net production for the 12 months ending December 31, 2000 was 30.4 MMcfe. At December 31, 2000, we had interests in 669 wells, including 83 service wells. We have budgeted through fiscal year ending December 31, 2001 approximately $25 million to $27 million for drilling and exploration activities. Our EBITDA for the twelve months ended December 31, 2000 was $29.8 million at an average realized price of $3.80 per Mcfe. We were incorporated under the laws of Delaware on May 11, 1989. Our executive offices and mailing address are 13760 Noel Road, Suite 1030, Dallas, Texas 75240-7336 and our telephone number at that address is 972-233-9906. On September 18, 2000, we changed our name from Queen Sand Resources, Inc. to DevX Energy, Inc. We also changed our fiscal year end from June 30 to December 31, effective December 31, 2000. The information in this transition report on Form 10-K is presented on a calendar year basis covering the 12-month periods ended December 31, unless otherwise stated. BUSINESS STRATEGY Our goal is to enhance shareholder value by expanding our oil and natural gas reserves, production levels and cash flow. Our strategy to achieve these goals consists of these elements: o pursuing managed asset growth through: o actively developing and exploiting our existing higher potential oil and natural gas properties; o selective acquisitions of high potential oil and natural gas assets that complement our existing properties, coupled with routine dispositions of non-core and lower potential properties; o an increased emphasis on exploration activities; and o targeted merger(s) where the consolidation with other companies will provide access to quality reserves within our core areas; o maintaining a capital and financial structure with prudent debt to equity ratios that will allow us to use cash generated from operations to fund growth in our production and reserves; and o maintaining a management team of senior industry executives to assist the company in enhancing and expanding its operational and exploration activities. 2 5 DEVELOPMENT AND EXPLOITATION OF EXISTING PROPERTIES. We have identified over 100 proved development locations and exploitation opportunities on our properties. We have prioritized these opportunities to concentrate on those higher impact projects that have the potential to replace production and to grow our reserves while maximizing the long-term return on our capital. Our opportunities include: o additional exploitation of well-defined locations on existing properties such as in the J.C. Martin field in south Texas; o in-fill drilling on our producing properties such as in the Gilmer field in east Texas; o recompletion of existing wells in behind-pipe intervals such as in the Lopeno and Volpe fields in south Texas; and o developing proved undeveloped and probable reserves by drilling low risk, long-lived natural gas wells in the shallow New Albany Shale formation in Kentucky. PROPERTY ACQUISITIONS AND DIVESTITURES. We are pursuing the acquisition of oil and natural gas properties that we believe will provide us with a combination of increased production, reserve growth and exploration potential. Although we are currently weighted towards natural gas reserves, we continue to pursue opportunities for oil reserves as well as natural gas reserves. While the acquisition market is currently very competitive, we believe that there are opportunities to acquire high quality oil and natural gas properties with these characteristics in the mid-continent and southwest regions of the United States, where we have established core areas. In all property acquisitions, the company will be seeking to become the operator. We will also continue to routinely evaluate our portfolio of properties and periodically divest non-core or low potential properties. EXPLORATION. The acquisition market is currently very competitive, especially for transactions that exceed $50 million. These properties are generally sold on a tender bid basis which has the effect of bidding up the price and maximizing the return to the seller. As a result, we have determined that it is no longer prudent to rely solely on acquisitions for asset growth. Our growth strategy has evolved from being primarily acquisition driven to a more balanced approach with an increased emphasis on exploration opportunities. We believe that this balanced approach will provide for a lower average reserve replacement cost, thereby improving our financial results. In order to diversify our exposure, we generally acquire larger interests in company-operated, low risk projects and smaller interests in higher risk/high impact exploration properties. Our plan is for much of our exploration effort to be conducted with partners who bring a unique experience, expertise or ownership position in the prospect area of interest and have a successful track record. MERGER OPPORTUNITIES. With our substantially de-leveraged balance sheet, stronger cash flow following the Recapitalization (see "Recent Developments") and our long-life reserves, we are actively evaluating the Company's fit in a consolidating industry, and considering various alternatives. This could result in our purchasing properties or a company that would enhance the value of the Company or in selling the Company to another company to create immediate shareholder value. CAPITAL AND FINANCIAL STRUCTURE. Our objective is to use a portion of the net proceeds of our public offering of common stock (see "Recent Developments") and internally generated cash flow to fund our exploration, development and exploitation programs. We believe that we can finance our acquisition opportunities at attractive costs with a combination of equity and debt. MANAGEMENT TEAM. During the course of fiscal 2000, we added several seasoned senior oil and gas industry executives with experience in building stockholder value and in the management of exploration and development projects. We also increased the number of technical personnel during the year. 3 6 RECENT DEVELOPMENTS THE RECAPITALIZATION. On October 31, 2000, we completed a recapitalization (the "Recapitalization") which included: (a) a reverse stock split of one common share for every 156 shares of our common stock; (b) the exchange of all preferred stock then outstanding, all warrants exercisable for shares of common stock and all unexercised common stock repricing rights for 732,500 shares of post reverse-split common stock; and (c) the repurchase of $75 million face value of our senior notes for approximately $52.5 million. Our stockholders approved the Recapitalization at a stockholders meeting held on September 18, 2000. THE OFFERING. During the months of October and November 2000, we completed the offering of an aggregate of 11,500,000 shares of post reverse split common stock at a price to the public of $7.00 per share (the "Offering"). The sale of 10,000,000 shares under the Offering was completed on October 31, 2000, and a further 1,500,000 shares were sold to the underwriters on November 29, 2000 pursuant to the exercise of their overallotment option. The net proceeds to the company, after deducting the underwriters' discount and offering expenses, were approximately $73.1 million. Approximately $66.5 million of the net proceeds of the Offering were applied to reduce debt and the remainder was applied to working capital of the company. As a result of the completion of the Recapitalization and the Offering, our company: o reduced the face value of our outstanding debt to $50 million; o eliminated all outstanding preferred stock; o eliminated the dilutive effects of the conversion and repricing rights held by some of our stockholders; o improved our liquidity by modifying the indenture governing our senior notes to permit us to increase our senior working capital facility from $35 million to $48.5 million; and o enabled us to list our common stock on the Nasdaq National Market under the trading symbol "DVXE." MANAGEMENT TEAM AND BOARD CHANGES. Ted Collins, Jr. and Eli Rebich resigned from the Board of Directors in May and June 2000, respectively. On September 15, 2000, Ronald I. Benn resigned as Chief Financial Officer and was replaced by William W. Lesikar. On October 6, 2000, Joseph T. Williams joined the company as Chairman. On October 26, 2000, Robert L. Keiser and Jerry B. Davis were appointed to the Board of Directors. On November 14, 2000, Patrick J. Keeley was also appointed to the Board of Directors. On December 7, 2000, Bruce I. Benn and Robert P. Lindsay resigned their respective positions as Executive Vice President and Chief Operating Officer. PRINCIPAL OIL AND NATURAL GAS PROPERTIES As of December 31, 2000, we owned interests in 586 gross producing wells, representing 155 net wells. The following is an overview of our major fields, by area. EAST TEXAS GILMER FIELD. The Gilmer field consists of 45 natural gas wells that cover approximately 9,030 gross acres in Upshur County in east Texas. The wells produce from the Cotton Valley Lime formation at a depth of approximately 11,500 feet to 12,000 feet. Goldston Oil Corporation, or Goldston, has an 80% working interest in, and is the operator of, our wells, which are in the heart of the Gilmer field. We own a 47.5% net profits interest in Goldston's working interest. The Gilmer field is located on the northwestern flank of the Sabine Uplift. The initial well in the field was drilled in 1986 and the field was delineated over the following ten years. The reservoirs are characterized by low permeability, depletion drive mechanisms and require stimulation. Well spacing is currently four wells per 640-acre 4 7 block for most of the units in the field. A field dedicated treating plant and centralized compression system provides the operator control in marketing the natural gas. Our average daily net production from the Gilmer field in December 2000 was approximately 10 MMcf of natural gas and 138 Bbls of oil, aggregating 10.7 MMcfe. Seven new wells have been drilled since June 2000, an eighth well is being drilled and ten additional proved undeveloped locations are scheduled to be drilled. Depending upon economic conditions, the property's value could be increased by accelerating production through additional down spacing. SOUTH TEXAS J.C. MARTIN FIELD. The J.C. Martin field consists of 84 producing natural gas wells that cover approximately 8,300 gross acres in Zapata County, Texas on the Mexican border. The field primarily produces from the Lobo 1, 3 and 6 series of sands in the Wilcox formation at depths of approximately 8,000 feet to 10,000 feet. Our interests consist of (a) a 13.33% perpetual, non-participating mineral royalty interest covering the Mecom family ranch and (b) an 80% net profits interest in Devon Energy Corporation's 20% working interest in the ranch. Coastal Oil Corporation, or Coastal, operates all of the wells. The reservoirs are low permeability, producing through pressure depletion and requiring fracture stimulations. A portion of our royalty interest in this property is the subject of litigation involving the predecessor owner. For further description of this litigation, see "Item 3. Legal Proceedings." Our average daily net production from the J.C. Martin field in December 2000 was 7 MMcfe. Two new wells have been drilled since January 2001, and a third well is being drilled. The first two wells had initial production rates of 2,300 Mcf per day and 1,400 Mcf per day, respectively, net to our interest. Some wells drilled since 1998 in this field tested natural gas from a deeper Cretaceous zone, the Navarro. This zone previously had not produced on the lease but had produced significant volumes to the north. We believe that there may be additional potential on the Mecom Ranch for this zone as only six wells have actually penetrated the Cretaceous zone. We also believe that potential exists for reserves in the Middle Wilcox zones at approximately 5,000 feet to 6,000 feet. LOPENO AND VOLPE FIELDS. The Lopeno and Volpe fields are located in Zapata County, Texas. These fields contain 24 wells. All of the wells produce from multiple reservoirs in the Upper Wilcox formation. Cody Energy, LLC is the operator of the majority of the wells with Dominion Production & Exploration, Inc. operating the remainder. We own interests in almost 4,700 gross acres in the Lopeno and Volpe fields. The Lopeno field is an extension of a field originally discovered in 1952. Over 20 sands have produced in the field at depths ranging from 6,500 feet to 12,000 feet. Typical of the numerous Upper Wilcox fields along the Texas Gulf Coast, the Lopeno field is highly faulted and overpressured. The Volpe field is also a Wilcox field located 8 miles north of Lopeno, Texas. A well was drilled directionally along the trapping fault and produced from the Middle Wilcox formation. Twelve proved undeveloped locations have been identified in these fields. Until June 30, 2000, we owned a 66.66% net profits interest in working interests owned by Choctaw II Oil & Gas Ltd., or Choctaw. Choctaw's working interests vary from 15.7% to 75%. Effective June 30, 2000, we sold our net profits interests in the Lopeno and Volpe fields, and we purchased primarily working interests in these properties as well as some additional interests in the Lopeno and Volpe area. As a result of this sale, our economic interest in the Lopeno and Volpe properties has been reduced by approximately one-half and we have converted substantially all of the remaining economic interest from net profits interests to working interests. Our average daily net production from the fields in December 2000 was 600 Mcfe of natural gas. We believe that the production in these fields can be enhanced through workovers and accelerated drilling for the shallow, behind-the-pipe reserves. 5 8 KENTUCKY NASGAS FIELD. We own working interests ranging between 60% and 100% in approximately 14,000 gross acres in Meade, Hardin and Breckinridge Counties, Kentucky. There are currently 32 gross producing natural gas wells located on our leases in Meade and Hardin Counties. These wells produce from the New Albany Shale formation at depths of approximately 850 feet. The shale zone has two porosity members and averages 80 feet in thickness. In addition to the natural gas wells, we also own an interest in two salt-water disposal wells and a related natural gas gathering system. Natural gas reserves in the New Albany Shale formation are long-lived reserves, generally lasting over 50 years. Our average daily net production from the Nasgas field in December 2000 was 400 Mcf. MID-CONTINENT We own interests in oil and gas assets located in the Texas panhandle, Oklahoma and Kansas, collectively referred to as the mid-continent assets. The mid-continent assets include 212 wells in 25 fields. These reserves are concentrated in high quality fields with the value evenly distributed over diverse, well-known reservoirs with long production histories supported by stable production declines. These reserves are long-lived assets with a productive life of 40 years and a reserves-to-production ratio of 15 years. An experienced production company operates each of these properties with focused operations in their respective areas. We own net profits overriding royalty interests in each of these properties. The net daily production from these properties in December 2000 was 100 Bbls and 5.8 MMcf, or 6.4 MMcfe. EXPLORATION, DEVELOPMENT AND EXPLOITATION ACTIVITIES During the past several months, we have entered into two exploration joint ventures, one of which focuses primarily on west Texas/Permian Basin opportunities and the other focuses primarily on south Texas prospects. Our plans for the year ending December 31, 2001 call for allocating between 15% and 35% of our capital expenditures to exploration activities. Our development drilling program is generated largely through our internal technical evaluation efforts and as a result of our obtaining undeveloped acreage in connection with producing property acquisitions. In addition, there are numerous opportunities for in-fill drilling on our leases currently producing oil and natural gas. We intend to continue to pursue development drilling opportunities which offer potentially significant returns to us. Our exploitation activities consist of the evaluation of additional reserves through workovers, behind-the-pipe recompletions and secondary recovery operations. During the year ended December 31, 2000, we participated in drilling 20 gross, or 5.3 net, wells, of which 15 gross, or 3.8 net, were productive. However, we cannot assure you that this past rate of drilling success will continue in the future. We are currently pursuing development drilling projects in 6 different fields and anticipate continued growth in drilling activities. At December 31, 2000, we had identified over 100 proved development locations on our acreage. We expect to spend approximately $25 million to $27 million on exploration, development and exploitation projects during the fiscal year ending December 31, 2001. The following is a brief discussion of our primary areas of development and exploitation activity: EAST TEXAS GILMER FIELD. We are currently engaged in an in-fill drilling program at the Gilmer field. This development program began in May 2000, and we have kept one rig drilling continuously in the field since. As of March 1, 2001, we have completed six wells, are completing a seventh well, and are drilling an eighth well. We believe the operator intends to keep the rig drilling in the Gilmer field and has identified an additional 22 potential locations, 10 of which are classified as proved undeveloped locations. 6 9 SOUTH TEXAS J.C. MARTIN FIELD. The J.C. Martin field produces from the Lobo Trend. Intense faulting has created many separate reservoirs that are over-pressured and highly faulted with numerous stacked sands. A 3D seismic study over the field has identified multiple new locations and initiated a new round of drilling. Since we acquired our interest in 1998, 23 wells have been drilled, 5 of which were drilled in 2000. In addition to the Lobo reservoirs evaluated in the reserve report, we believe upside potential exists in the Navarro and Middle Wilcox zones. We recently recompleted one well in the Middle Wilcox. The deeper Cretaceous formation, the Navarro zone, also produces in this field. Since December 2000, we have drilled two wells, are drilling a third well, and expect to drill three more wells this year. LOPENO AND VOLPE FIELDS. We believe meaningful potential exists in the Lopeno and Volpe fields to increase production. Over twenty sands have produced in the Lopeno field and most wells have multiple behind-the-pipe zones. Accelerated drilling for some of the shallower zones may be justified, improving their present value. Twelve proved undeveloped locations have been identified in the Lopeno and Volpe fields that would develop Upper Wilcox sands. We are currently working with the operator to pursue the necessary workovers and additional drilling. KENTUCKY NASGAS FIELD. We believe that the Nasgas field presents opportunities for low cost developmental drilling at depths of less than 1,000 feet. We are in the process of completing a 25-well drilling program, which commenced during October 2000. We have commenced drilling operations on the first of 50 additional wells we plan to drill during 2001. These wells have long lives, often exceeding 50 years. We anticipate our share of capital expenditures in the Nasgas field will be approximately $7 million through December 2001. EXPLORATION JOINT VENTURES We have recently entered into two exploration joint ventures. Both utilize 3-D seismic analysis to explore for potential oil and gas reservoirs. The first agreement was signed in September 2000 and focuses primarily on the Permian Basin in west Texas. The majority of the prospects target the Wolfcamp formation at 6,000 feet to 8,000 feet. As of March 2001, we have participated in seven wells with an ownership interest of between 1.3% and 27.1%, or an average of 7.1%. Three are producing, three are waiting on completion and one was a dry hole. We are currently negotiating a participation in two additional 3-D seismic surveys in this area that would encompass approximately thirty square miles. We expect our interest in additional prospects in Pecos County, Texas to range between 10% and 15% and for prospects other than those in Pecos County to range between 25% and 75%. The second agreement was signed in January 2001 and focuses primarily on the Frio and Wilcox formations in south Texas. These prospects are generally higher reserve potential and higher risk than those in west Texas. As of March 2001, we have committed to participating in three prospects in this joint venture. The first well is anticipated to spud prior to the end of March 2001. We expect to participate with interests ranging between 15% and 30% in prospects in this venture. We expect to spend 15% to 35% of our total capital budget on exploration activities. MARKETING Our oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. We do not refine or process any of the oil and natural gas we produce. We are currently able to sell, under contract or in the spot market, all of the oil and the natural gas we are capable of producing at current market prices. Substantially all of our oil and natural gas is sold under short term contracts or contracts providing for periodic adjustments or in the spot market; therefore, our revenue streams are highly sensitive to changes in current market prices. Our market for natural gas is pipeline companies as opposed to end users. For a description of the risks of changes in the prices for oil and natural gas, see "Item 1. Business - Risk Factors - Risks Related to Our Business -- Our profitability is highly dependent on the prices for oil and natural gas, which can be extremely volatile." 7 10 In an effort to reduce the effects of the volatility of the price of oil and natural gas on our operations and cash flow, we adopted an approach of hedging oil and natural gas prices whenever market prices are in excess of the prices anticipated in our operating budget and financial plan through the use of commodity futures, options and swap agreements. We do not engage in speculative trading. For further description of our hedging strategy, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Changes in Prices and Hedging Activities." For the year ended December 31, 2000, Goldston Oil Corporation accounted for approximately 31% of our oil and natural gas sales, Coastal Oil and Gas, Inc. accounted for approximately 18% of our oil and natural gas sales, Devon Energy Corporation accounted for approximately 13% of our oil and natural gas sales, and Kaiser Francis Oil Company accounted for approximately 14% of our oil and natural gas sales. We do not believe that the loss of any of these buyers would have a material effect on our business or results of operations as we believe we could readily locate other buyers. However, short term disruptions could occur while we seek alternative buyers or while lines were being connected to other pipelines. OIL AND NATURAL GAS RESERVES The following tables summarize information regarding our estimated proved oil and natural gas reserves as of December 31, 1998, 1999 and 2000. All of these reserves are located in the United States. The estimates relating to our proved oil and natural gas reserves and future net revenues of oil and natural gas reserves at December 31, 1998 are based on reserve reports prepared by our internal petroleum engineers. The estimates at December 31, 1999 with respect to the Morgan Properties included in this Annual Report on Form 10-K are based upon reports prepared by Ryder Scott Company. The estimates at December 31, 1999 other than with respect to the Morgan Properties included in this form are based upon reports prepared by H.J. Gruy and Associates, Inc. The estimates at December 31, 2000 are based on reserve reports prepared by Ryder Scott Company. In accordance with guidelines of the SEC, the estimates of future net cash flows from proved reserves and their SEC PV-10 are made using oil and natural gas sales prices in effect as of the dates of the estimates and are held constant throughout the life of the properties. Our estimates of proved reserves, future net cash flows and SEC PV-10 were estimated using the following weighted average prices, before deduction of production taxes:

DECEMBER 31 ------------------------ 2000 1999 1998 ------ ------ ------ Natural gas (per Mcf) $10.92 $ 2.35 $ 1.84 Oil (per Bbl) $25.88 $23.91 $10.79

Reserve estimates are imprecise, and may be expected to change as additional information becomes available. Furthermore, estimates of oil and natural gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of these data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgement. Reserve reports of other engineers might differ from the reports contained herein. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of this estimate. Future prices received for the sale of oil and natural gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, we cannot assure you that the reserves set forth herein will ultimately be produced or can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. The discounted future net cash inflows should not be construed as representative of the fair market value of the proved oil and natural gas properties, since discounted future net cash inflows are based upon projected cash inflows which do not provide for changes in oil and natural gas prices nor for escalation of expenses and capital costs. The meaningfulness of these estimates is highly dependent upon the accuracy of the assumptions upon which they were based. 8 11 All reserves are evaluated at constant temperature and pressure, which can affect the measurement of natural gas reserves. Operating costs, development costs and some production-related and ad valorem taxes were deducted in arriving at the estimated future net cash flows. No provision was made for income taxes, and the estimates were based on operating methods and existing conditions at the prices and operating costs prevailing at the dates indicated above. The estimates of the SEC PV-10 from future net cash flows differ from the Standardized Measure set forth in the notes to our consolidated financial statements, which is calculated after provision for future income taxes. We cannot assure you that these estimates are accurate predictions of future net cash flows from oil and natural gas reserves or their present value. For additional information concerning our oil and natural gas reserves and estimates of future net revenues attributable thereto, see Note 12 of the notes to consolidated financial statements included in this Annual Report on Form 10-K. COMPANY RESERVES The following tables set forth our proved reserves of oil and natural gas and the SEC PV-10 thereof for each year in the three-year period ended December 31, 2000. PROVED OIL AND NATURAL GAS RESERVES(1)

DECEMBER 31 ------------------------------ 2000 1999 1998 -------- -------- -------- NATURAL GAS RESERVES (MMcf): Proved Developed Reserves 84,669 86,044 120,373 Proved Undeveloped Reserves 45,107 53,954 51,632 -------- -------- -------- Total Proved Reserves of natural gas 129,776 139,998 172,005 OIL RESERVES (MBbl): Proved Developed Reserves 1,253 1,937 4,317 Proved Undeveloped Reserves 108 2,516 2,562 -------- -------- -------- Total Proved Reserves of oil 1,361 4,453 6,879 TOTAL PROVED RESERVES (MMcfe) 137,942 166,716 213,279

SEC PV-10 OF PROVED RESERVES(1)

DECEMBER 31 ------------------------------ 2000 1999 1998 -------- -------- -------- (IN THOUSANDS) SEC PV-10(2): Proved Developed Reserves $392,086 $ 88,007 $ 94,871 Proved Undeveloped Reserves 142,133 43,115 17,700 -------- -------- -------- TOTAL SEC PV-10 $534,219 $131,122 $112,571

--------- (1) The data shown at December 31, 1998 is based upon reserve reports prepared by our internal petroleum engineers. The data shown at December 31, 1999 with respect to the Morgan Properties is based upon reserve reports prepared by Ryder Scott Company. The estimates at December 31, 1999 other than with respect to the Morgan Properties are based upon reserve reports prepared by H.J. Gruy and Associates, Inc. The estimates at December 31, 2000 are based on reserve reports prepared by Ryder Scott Company. (2) SEC PV-10 differs from the Standardized Measure set forth in the notes to our consolidated financial statements, which is after a provision for future income taxes. These amounts do not reflect the impact of any of our derivative contracts used to hedge commodity price risk, as the contracts are financial contracts and do not contemplate physical delivery of oil or natural gas. 9 12 Except for the effect of changes in oil and natural gas prices no major discovery or other favorable or adverse event is believed to have caused a significant change in these estimates of our reserves since December 31, 2000. Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves," filed with the United States Department of Energy, no other estimates of total proven net oil and natural gas reserves have been filed by us with, or included in any report to, any United States authority or agency pertaining to our individual reserves since the beginning of our last fiscal year. Reserves reported on Form EIA 23 are comparable to the reserves reported by us herein. OPERATIONS DATA PRODUCTIVE WELLS The following table sets forth the number of total gross and net productive wells in which we owned an interest as of December 31, 2000.

GROSS NET --------------------- --------------------- OIL GAS TOTAL OIL GAS TOTAL ----- ----- ----- ----- ----- ----- Texas 150 166 316 37.2 35.0 72.3 New Mexico 29 -- 29 28.5 -- 28.5 Oklahoma -- 153 153 -- 19.6 19.6 Kentucky -- 32 32 -- 22.4 22.4 Other(1) 2 54 56 1.4 10.8 12.1 ----- ----- ----- ----- ----- ----- Total 181 405 586 67.1 87.8 154.9 ===== ===== ===== ===== ===== =====

---------- (1) Represents wells located in Alabama, Kansas, Louisiana and Wyoming. PRODUCTION ECONOMICS The following table sets forth certain operating information for the periods presented.

YEARS ENDED DECEMBER 31 ------------------------------------ 2000 1999 1998 ---------- ---------- ---------- OPERATING DATA PRODUCTION VOLUMES: Natural gas (MMcf) 9,797 11,441 9,931 Oil (MBbl) 216 339 481 Total (MMcfe) 11,096 13,474 12,814 AVERAGE SALES PRICE, NET OF CASH SETTLEMENTS ON HEDGE POSITIONS: Natural gas (per Mcf) $ 3.69 $ 2.24 $ 2.16 Oil (per Bbl) 27.89 14.05 13.26 SELECTED EXPENSES (PER MCFE): Production taxes $ 0.16 $ 0.08 $ 0.15 Lease operating expense, including ad valorem taxes 0.55 0.39 0.66 General and administrative 0.41 0.27 0.19 Depreciation, depletion and amortization (1) 0.77 0.68 0.79

---------- (1) Represents depreciation, depletion and amortization of oil and natural gas properties only. 10 13 DRILLING ACTIVITY The following table sets forth our gross and net working interests in exploratory and development wells (but excluding injection or service wells) drilled during the indicated periods.

YEARS ENDED DECEMBER 31 ---------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ----- ----- EXPLORATORY: Oil 2 0.2 1 0.2 -- -- Natural gas 1 -- -- -- -- -- Dry 2 1.0 1 1.0 -- -- ----- ----- ----- ----- ----- ----- Total 5 1.2 2 1.2 -- -- DEVELOPMENT: Oil 1 0.8 -- -- 5 2.0 Natural gas 11 2.8 9 1.9 33 11.7 Dry 3 0.5 1 0.5 2 1.2 ----- ----- ----- ----- ----- ----- Total 15 4.1 10 2.4 40 14.9 TOTAL: Oil 3 1.0 1 0.2 5 2.0 Natural gas 12 2.8 9 1.9 33 11.7 Dry 5 1.5 2 1.5 2 1.2 ----- ----- ----- ----- ----- ----- Total 20 5.3 12 3.6 40 14.9

Since December 31, 2000, we have successfully drilled 6 gross, 1.2 net, wells, through March 1, 2001. At March 1, 2001, we were in the process of drilling 29 gross, 26.0 net, wells. DEVELOPED AND UNDEVELOPED ACREAGE The following table sets forth the approximate gross and net acres in which we owned an interest as of December 31, 2000.

DEVELOPED UNDEVELOPED ----------------- ----------------- GROSS NET GROSS NET ------- ------- ------- ------- Texas 47,203 13,777 6,497 1,300 New Mexico 14,280 14,126 -- -- Louisiana 302 302 6,081 3,315 Oklahoma 37,440 5,336 -- -- Kentucky 636 428 13,886 12,748 Other(1) 20,510 5,190 -- -- ------- ------- ------- ------- Total 120,371 39,159 26,464 17,363 ======= ======= ======= =======

---------- (1) Represents acreage located in Alabama, Colorado, Kansas, and Wyoming. MARKETS AND COMPETITION The oil and natural gas industry is highly competitive. Our competitors include major oil companies, other independent oil and natural gas concerns and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than ours. In addition, we encounter substantial competition in acquiring oil and natural gas properties, marketing oil and natural gas and hiring trained personnel. When possible, we try to avoid open competitive bidding for acquisition opportunities. The principal means of competition with respect to the sale of oil and natural gas production are product availability and price. While it is not possible for us to state accurately our position in the oil and natural gas industry, we believe that we represent a minor competitive factor. 11 14 The market for our oil and natural gas production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil and natural gas, the price of imports of oil and natural gas, access to natural gas pipelines and other transportation facilities and overall economic conditions. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. TITLE TO OIL AND NATURAL GAS PROPERTIES We have acquired interests in producing and non-producing acreage in the form of working interests, royalty interests, overriding royalty interests and net profits interests. Substantially all of our property interests, and the assignors' interests in the working or other interests in the underlying properties, are held pursuant to leases from third parties. The leases grant the lessee the right to explore for and extract oil and natural gas from specified areas. Consideration for these leases usually consists of a lump sum payment, such as a bonus, and a fixed annual charge, such as a delay rental, prior to production unless the lease is paid up and, once production has been established, a royalty based generally upon either the proceeds from the sale of oil and natural gas or the market value of oil and natural gas produced. Once wells are drilled, a lease generally continues so long as production of oil and natural gas continues. In some cases, leases may be acquired in exchange for a commitment to drill or finance the drilling of a specified number of wells to predetermined depths. Some of our non-producing acreage is held under leases from mineral owners or governmental entities which expire at varying dates. We are obligated to pay annual delay rentals to the lessors of some properties in order to prevent the leases from terminating. Title to leasehold properties is subject to royalty, overriding royalty, carried, net profits and other similar interests and contractual arrangements customary in the oil and natural gas industry, and to liens incident to operating agreements, liens relating to amounts owed to the operator, liens for current taxes not yet due and other encumbrances. As is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title examined prior to acquisition of developed acreage in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights. In many instances, title opinions may not be obtained if in our judgment it would be uneconomical or impractical to do so. The underlying properties are typically subject, in one degree or another, to one or more of the following: o royalties and other burdens and obligations, expressed and implied, under oil and gas leases; o overriding royalties and other burdens created by the assignor or its predecessors in title; o a variety of contractual obligations, including, in some cases, development obligations, arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; o liens that may arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements; o pooling, unitization and communitization agreements, declarations and orders; and o easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that these burdens and obligations affect the assignor's rights to production and the value of production from the underlying properties, they have been taken into account in calculating our interests and in estimating the size and value of the reserves attributable to our net profits interests and royalty interests. A substantial portion of our oil and natural gas property interests is in the form of non-operated, net profits interests and royalty interests. The net profits interests were conveyed to us by various assignors from the assignor's net revenue interests in the oil and natural gas properties burdened by the net profits interests and royalty interests (the 12 15 "underlying properties"). The assignors' net revenue interests are generally leasehold working interests less lease burdens. NET PROFITS INTERESTS. As the owner of net profits interests, we do not have the direct right to drill or operate wells or to cause third parties to propose or drill wells on the underlying properties. If an assignor or any other working interest owner proposes to drill wells on one of the underlying properties, then that assignor must give us notice of the proposal. Under an agreement covering the underlying property, we have the option to pay a specified percentage of the assignor's working interest share of the expenses of the well that is proposed. We would then become entitled to a net profits interest equal to the specified percentage multiplied by the assignor's net revenue interest in that well. However, if an assignor elects not to participate in the drilling of a well, we will not be able to participate in that well. Moreover, if an assignor owns less than a 100% working interest in a proposed well, and the other owners of working interests in that well elect not to participate in the well, the well will not be drilled unless the money to pay the costs allocable to the working interest owners who do not elect to participate in the well is obtained. The financial strength and the competence of the various assignors, and to a lesser extent the financial strength and the competence of other parties owning working interests in the underlying properties, may have an effect on when and whether wells get drilled on the underlying properties, and on whether operations are conducted in a prudent and competent manner. ROYALTY INTERESTS. The royalty interests are generally in the form of term royalty interests. The duration of these interests is the same as the underlying oil and natural gas lease. Some of the royalty interests are perpetual royalty interests which entitle the owner to a share of production from the underlying properties under both the current oil and natural gas lease and any replacement or successor oil and natural gas lease. In all cases, the royalty interests are non-operating interests, have little or no influence over oil and natural gas development or operation on the lands they burden but have limited cost bearing responsibilities. SALE AND ABANDONMENT OF UNDERLYING PROPERTIES. An assignor has the right to abandon any well or working interest included in the underlying properties if, in its opinion, the well or property ceases to produce or is not capable of producing oil or natural gas in commercially paying quantities. We may not control the timing of plugging and abandoning wells. The conveyances provide that the assignor's working interest share of the costs of plugging and abandoning uneconomic wells are deducted in calculating our net cash flow from the underlying property. The assignor can sell the underlying properties, subject to and burdened by the royalty interests, without our consent. Accordingly, the underlying properties could be transferred to a party with a weaker financial profile. REGULATION GENERAL FEDERAL AND STATE REGULATION Our oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal and state agencies. Failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with these laws. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. The Federal Energy Regulatory Commission, or FERC, regulates interstate natural gas transportation rates and service conditions, which affect the revenues received by us for sales of our production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B, or Order 636, that have significantly altered the marketing and transportation of natural gas. Order 636 mandates a fundamental restructuring of interstate pipeline 13 16 sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services the pipelines previously performed. One of FERC's purposes in issuing the orders is to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders on rehearing have been appealed and are pending judicial review. Because these orders may be modified as a result of the appeals, it is difficult to predict the ultimate impact of the orders on us. Generally, Order 636 has eliminated or substantially reduced the traditional role of intrastate pipelines as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting products to market. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index these rates to inflation, subject to some conditions and limitations. Finally, from time to time regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. ENVIRONMENTAL REGULATION The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our domestic activities are subject to a variety of environmental laws and regulations, including but not limited to, the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA, and the Safe Drinking Water Act, or SDWA, as well as state regulations promulgated under comparable state statutes. We are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected areas or species, and impose substantial liabilities for cleanup of pollution. Under the OPA, a release of oil into water or other areas designated by the statute could result in our being held responsible for the costs of remediating the release, OPA specified damages, and natural resource damages. The extent of that liability could be extensive, as set forth in the statute, depending on the nature of the release. A release of oil in harmful quantities or other materials into water or other specified areas could also result in our being held responsible under the CWA for the costs of remediation, and any civil and criminal fines and penalties. CERCLA and comparable state statutes, also known as "Superfund" laws, can impose joint and several retroactive liability, without regard to fault or the legality of the original conduct, on specified classes of persons for the release of a "hazardous substance" into the environment. In practice, cleanup costs are usually allocated among various responsible parties. Potentially liable parties include site owners or operators, past owners or operators under certain conditions, and entities that arrange for the disposal or treatment of, or transport hazardous substances found at the site. Although CERCLA, as amended, currently exempts petroleum, including but not limited to, oil, natural gas and natural gas liquids from the definition of hazardous substance, our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA. Furthermore, there can be no assurance that the exemption will be preserved in future amendments of CERCLA, if any. RCRA and comparable state and local requirements impose standards for the management, including treatment, storage, and disposal of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. From time to time, proposals have been made that would reclassify certain oil and natural gas wastes, including wastes generated during pipeline, drilling, and production operations, as "hazardous wastes" under RCRA which would make these solid wastes subject to much more stringent handling, transportation, storage, disposal, and clean-up requirements. This development could have a significant impact on our 14 17 operating costs. While state laws vary on this issue, state initiatives to further regulate oil and natural gas wastes could have a similar impact. Oil and natural gas exploration and production, and possibly other activities, have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties and in some instances require remediation. In addition, we have agreed to indemnify sellers of producing properties from whom we have acquired reserves against certain liabilities for environmental claims associated with these properties. While we do not believe that costs to be incurred by us for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, there can be no guarantee that these costs will not result in material expenditures. Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials occur, and we incur costs for waste handling and environmental compliance. Moreover, we are able to control directly the operations of only those wells for which we act as the operator. Notwithstanding our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. It is not anticipated that we will be required in the near future to expend amounts that are material in relation to our total capital expenditures program by reason of environmental laws and regulations, but inasmuch as these laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance. There can be no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. For a description of the risks associated with environmental regulations, see "- Risk Factors." EMPLOYEES As of March 6, 2001, we had 21 full-time employees consisting of 6 officers and 15 support staff. Three of the employees are based in Ottawa, Canada, 16 of the employees are located in the Dallas office, and 2 are on site in Kentucky. In addition, we regularly engage technical consultants and independent contractors to provide specific advice or to perform administrative or technical functions. RISK FACTORS RISKS RELATED TO OUR BUSINESS WE HAVE IN THE PAST EXPERIENCED NET LOSSES AND WE MAY EXPERIENCE NET LOSSES IN THE FUTURE, WHICH COULD MATERIALLY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS. Between the time we began operations in 1994 and December 31, 1999, we were not profitable on an annual basis. We experienced a net loss from continuing operations of approximately $71.1 million for the year ended December 31, 1998, and a net loss from continuing operations of approximately $10.7 million for the year ended December 31, 1999. For the year ended December 31, 2000, we had income from continuing operations of approximately $2.7 million. We may experience net losses in the future as we continue to incur significant operating expenses and to make capital expenditures. We may not sustain or increase profitability on a quarterly or annual basis in the future. At October 31, 2000, we eliminated an accumulated deficit of approximately $68.1 million in connection with a quasi-reorganization. 15 18 OUR PROFITABILITY IS HIGHLY DEPENDENT ON THE PRICES FOR OIL AND NATURAL GAS, WHICH CAN BE EXTREMELY VOLATILE. Our revenues, profitability and future growth substantially depend on prevailing prices for oil and natural gas. Prices for oil and natural gas can be extremely volatile. Among the factors that can cause this volatility are: o weather conditions; o the level of consumer product demand; o domestic and foreign governmental regulations; o the price and availability of alternative fuels; o political conditions in oil and natural gas producing regions; o the domestic and foreign supply of oil and natural gas; o the availability, proximity and capacity of gathering systems of natural gas; o the price of foreign imports; and o overall economic conditions. Prices for oil and natural gas affect the amount of cash flow available to us for capital expenditures and the repayment of our outstanding debt. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. In addition, because we currently produce more natural gas than oil, we face more risk with fluctuations in the price of natural gas than oil. We have used hedging contracts to reduce our exposure to price changes. HEDGING OUR PRODUCTION MAY CAUSE US TO FOREGO FUTURE PROFITS. To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into hedging arrangements for a portion of our oil and natural gas production. The hedges that we have entered into generally provide a "floor" or "cap and floor" on the prices paid for our oil and natural gas production over a period of time. Hedging arrangements may expose us to the risk of financial loss in some circumstances, including the following: o the other party to the hedging contract defaults on its contract obligations; or o there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Reduced revenues resulting from our hedging activities could have an adverse effect on our financial condition and operations. For the year ended December 31, 2000, our revenues were reduced by $3.5 million as a result of cash settlements made under our existing hedge contracts. We may have to make additional payments under these contracts in the future depending on the difference between actual and hedged prices of oil and natural gas. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. Some of our hedging arrangements contain a "cap" whereby we must pay the counter-party if oil or natural gas prices exceed the price specified in the contract. We are required to maintain letters of credit with our counter-parties, and we may be required to provide additional letters of credit if prices for oil and natural gas futures increase above the "cap" prices. The amount of these letters of credit is a function of the market value of oil and natural gas prices and the volumes of oil and natural gas subject to the contract. As a result, the value of these letters of credit will fluctuate with the market prices of oil and natural gas. These letters of credit are issued pursuant to our credit agreement and as a result utilize some of our borrowing capacity, reducing funds available to be borrowed under our credit agreement. IF WE ARE NOT ABLE TO REPLACE DEPLETED RESERVES, OUR FUTURE RESULTS OF OPERATIONS WILL BE ADVERSELY AFFECTED. The rate of production from oil and natural gas properties declines as reserves are depleted. Our proved reserves will decline as reserves are produced unless we acquire additional properties containing proved reserves, conduct successful exploration, development and exploitation activities on new or currently leased properties or identify additional formations with primary or secondary reserve opportunities on our properties. If we are not successful in 16 19 expanding our reserve base, our future oil and natural gas production, the primary source of our revenues, will be adversely affected. The level of our future oil and natural gas production and our results of operations are therefore highly dependent on the level of our success in finding and acquiring additional reserves. Our ability to find and acquire additional reserves depends on our generating sufficient cash flow from operations and other sources of capital, including borrowings under our credit agreement. We cannot assure you that we will have sufficient cash flow or cash from other sources to expand our reserve base. Our ability to continue acquiring producing properties or companies that own producing properties assumes that major integrated oil companies and independent oil companies will continue to divest many of their oil and natural gas properties. We cannot assure you that these divestitures will continue or that we will be able to acquire producing properties at acceptable prices. WE MAY HAVE DIFFICULTY FINANCING OUR PLANNED GROWTH AND CAPITAL EXPENDITURES. We have experienced and expect to continue to experience substantial capital expenditure and working capital needs as a result of our exploration, development, exploitation and acquisition strategy. In the future, we may require financing, in addition to cash generated from our operations and the proposed offering of our common stock, to fund our planned growth and capital expenditures. Over the past two years, we have experienced constraints on our ability to arrange additional capital to fund our business plan. Although we were able to borrow an additional $35 million under our credit agreement as of March 6, 2001, our lenders could reduce our borrowing limit. If additional capital resources are unavailable, we will be unable to grow our business and we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. RESTRICTIVE DEBT COVENANTS LIMIT OUR ABILITY TO FINANCE OUR OPERATIONS, FUND OUR CAPITAL NEEDS AND ENGAGE IN OTHER BUSINESS ACTIVITIES THAT MAY BE IN OUR INTEREST. Our credit agreement and the indenture governing our 12 1/2% senior notes due 2008 contain significant covenants that, among other things, restrict our ability to: o dispose of assets; o incur additional indebtedness; o repay other indebtedness; o pay dividends; o enter into specified investments or acquisitions; o repurchase or redeem capital stock; o merge or consolidate; or o engage in specified transactions with subsidiaries and affiliates and our other corporate activities. Also, our credit agreement requires us to maintain compliance with the financial ratios included in that agreement. Our ability to comply with these ratios may be affected by events beyond our control. A breach of any of these covenants or our inability to comply with the required financial ratios could result in a default under our credit agreement. We have in the past been in default of some covenants under our previous credit agreement. All of these defaults were waived by the lenders. However, if we default under our current credit agreement, our lender may declare all amounts borrowed under the credit agreement, together with accrued interest, to be due and payable. If we do not repay the indebtedness promptly, our lender could then foreclose against any collateral securing the payment of the indebtedness. Substantially all of our oil and natural gas interests secure our credit agreement. OUR ABILITY TO GENERATE SUFFICIENT CASH TO SERVICE OUR DEBT AND REPLACE OUR RESERVES DEPENDS ON MANY FACTORS BEYOND OUR CONTROL. We rely on cash from our operations to pay the principal and interest on our debt. Our ability to generate cash from operations depends on the level of production from our properties, general economic conditions, including the prices paid for oil and natural gas, success in our exploration, development and exploitation activities, and legislative, 17 20 regulatory, competitive and other factors beyond our control. Our operations may not generate enough cash to pay the principal and interest on our debt. WE CANNOT ASSURE YOU THAT WE WILL BE SUCCESSFUL IN MANAGING OUR GROWTH. The success of our future growth will depend on a number of factors, including: o our ability to timely explore, develop and exploit acquired properties; o our ability to continue to attract and retain skilled personnel; o our ability to continue to expand our technical, operational and administrative resources; and o the results of our drilling program. Our growth could strain our financial, technical, operational and administrative resources. Our failure to successfully manage our growth could adversely affect our operations and net revenues through increased operating costs and revenues that do not meet our expectations. WE MAY PURCHASE OIL AND NATURAL GAS PROPERTIES WITH LIABILITIES OR RISKS WE DID NOT KNOW ABOUT OR THAT WE DID NOT CORRECTLY ASSESS, AND, AS A RESULT, WE COULD BE SUBJECT TO LIABILITIES THAT COULD ADVERSELY AFFECT OUR RESULTS OF OPERATIONS. We evaluate and pursue acquisition opportunities, primarily in the mid-continent and southwest regions of the United States. Before acquiring oil and natural gas properties, we estimate the recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors relating to the properties. We believe our method of review is generally consistent with industry practices. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not generally perform inspections on every well, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. Even if we identify problems, the seller may not be willing or financially able to give contractual protection against these problems, and we may decide to assume environmental and other liabilities in connection with acquired properties. If we acquire properties with risks or liabilities we did not know about or that we did not correctly assess, our financial condition and results of operations could be adversely affected. THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS THAT COULD CAUSE SUBSTANTIAL LOSSES. Drilling activities involve the risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Whether a well is productive and profitable depends on a number of factors, including the following, many of which are beyond our control: o general economic and industry conditions, including the prices received for oil and natural gas; o mechanical problems encountered in drilling wells or in production activities; o problems in title to our properties; o weather conditions which delay drilling activities or cause producing wells to be shut down; o compliance with governmental requirements; and o shortages in or delays in the delivery of equipment and services. If we do not drill productive and profitable wells in the future, our financial condition and results of operations could be materially and adversely affected due to decreased cash flow and net revenues. 18 21 In addition to the substantial risk that we may not drill productive and profitable wells, the following hazards are inherent in oil and natural gas exploration, development, exploitation, production and gathering, including: o unusual or unexpected geologic formations; o unanticipated pressures; o mechanical failures; o blowouts where oil or natural gas flows uncontrolled at a wellhead; o cratering or collapse of the formation; o explosions; o pollution; and o environmental accidents such as uncontrollable flows of oil, natural gas or well fluids into the environment, including groundwater contamination. We could suffer substantial losses from these hazards due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We carry insurance that we believe is in accordance with customary industry practices for companies of our size. However, we do not fully insure against all risks associated with our business either because this insurance is not available or because we believe the cost is prohibitive. The occurrence of an event that is not covered, or not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. OUR EXPLORATION ACTIVITIES INVOLVE A HIGH DEGREE OF RISK AND MAY NOT BE COMMERCIALLY SUCCESSFUL. Oil and natural gas exploration involves a high degree of risk that hydrocarbons will not be found, that they will not be found in commercial quantities, or that their production will be insufficient to recover drilling, completion and operating costs. The 3-D seismic data and other technologies we may use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically producible. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Furthermore, completion of a well does not guarantee that it will be profitable or even that it will result in recovery of drilling, completion and operating costs. Therefore, we may not earn revenues with respect to, or recover costs spent on, our exploration activities. WE CANNOT CONTROL THE DEVELOPMENT OF A SUBSTANTIAL PORTION OF OUR PROPERTIES BECAUSE OUR INTERESTS ARE IN THE FORM OF NON-OPERATED NET PROFITS INTERESTS AND OVERRIDING ROYALTY INTERESTS. A substantial portion of our oil and natural gas property interests are in the form of non-operated, net profits interests and royalty interests. As the owner of non-operated net profits interests and royalty interests, we do not have the direct right to drill or operate wells or to cause third parties to propose or drill wells on the underlying properties. As a result, the success and timing of our drilling and development activities on those properties operated by others depend upon a number of factors outside of our control, including: o the timing and amount of capital expenditures; o the operator's expertise and financial resources; o the approval of other participants in drilling wells; and o the selection of suitable technology. If the operators of these properties do not conduct drilling and development activities on these properties, then our results of operations may be adversely affected. WE MAY LOSE TITLE TO OUR ROYALTY INTEREST IN THE J.C. MARTIN FIELD AS A RESULT OF LITIGATION OVER TITLE TO THE ROYALTY INTEREST. A portion of our landowner royalty on the J.C. Martin field, which comprises approximately 11% of our total SEC PV-10 value as of December 31, 2000, is currently subject to a lawsuit that may create uncertainty as to the title 19 22 to our royalty interest. A favorable order of summary judgment has been rendered in favor of the pension funds managed by the entity that sold us the properties. The order has been appealed. Eight million dollars of the purchase price we paid for the Morgan Properties, which include our royalty interest in the J.C. Martin field, are currently in escrow pending the resolution of this lawsuit. If the summary judgment is overturned and a final judgment is later entered against the entity who sold us this property and that judgment unwinds the original transaction in which the entity acquired its interest in the J.C. Martin field, the escrowed monies would be returned to us and we would be required to convey to the plaintiff our royalty interest in the J.C. Martin field and the net proceeds received by us since the date we acquired our interest. IF A BANKRUPTCY COURT TREATS ANY OF OUR NET PROFITS INTERESTS AS CONTRACT RIGHTS INSTEAD OF REAL PROPERTY INTERESTS, WE COULD LOSE ALL OF THE VALUE OF THOSE INTERESTS. We cannot assure you whether a court in the states of Kansas and Oklahoma would treat the net profits interests as contract rights or real property interests. Our net profits interests in these states comprise 14% of our SEC-PV-10 as of December 31, 2000. If any of the assignors become involved in bankruptcy proceedings in these states, we face the risk that our net profits interests might be treated by a bankruptcy court as contract rights instead of real property interests. If the bankruptcy court treats our net profits interests as contract rights, then we would be treated as an unsecured creditor in the bankruptcy, and under the terms of the bankruptcy plan, we could lose all of the value of the net profits interests. If the bankruptcy court treats the net profits interests as real property interests, then our interests should not be materially affected. ANY NEGATIVE VARIANCE IN OUR ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUES COULD AFFECT THE CARRYING VALUE OF OUR ASSETS, OUR INCOME AND OUR ABILITY TO BORROW FUNDS. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve data included in this report represent only estimates. In addition, the estimates of future net revenue from proved reserves and their present value are based on assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and natural gas reserves, future net revenue from proved reserves and the present value of proved reserves for the oil and natural gas properties described in this report are based on the assumption that future oil and natural gas prices remain the same as oil and natural gas prices at December 31, 2000. The NYMEX prices as of December 31, 2000, used for purposes of our estimates were $26.83 per Bbl of NYMEX Light Sweet Crude and $10.415 per MMbtu for Henry Hub natural gas. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of our reserves. WE MAY BE REQUIRED TO WRITE DOWN THE CARRYING VALUE OF OUR PROVED PROPERTIES UNDER ACCOUNTING RULES AND THESE WRITE-DOWNS COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION. There is a risk that we will be required to write-down the carrying value of our oil and natural gas properties when oil and natural gas prices are low. In addition, write-downs may occur if we have: o downward adjustments to our estimated proved reserves, o increases in our estimates of development costs or o deterioration in our exploration and exploitation results. We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, the net capitalized costs of oil and natural gas properties may not exceed a ceiling limit that is based on the present value, based on flat prices at a single point in time, of estimated future net revenues from proved reserves, discounted at 10%. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of this excess to earnings in the quarter in which the excess occurs. At June 30, 1998, we were required to write down the carrying value of our oil and natural gas properties by $28.2 million. At December 31, 1998, we were required to write down the carrying value of our oil and natural gas properties by an additional $35 million. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect cash flow from operating activities, but it does reduce the book value of our net tangible assets and stockholders' equity. 20 23 IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST OTHER OIL AND GAS COMPANIES, WE MAY BE UNABLE TO ACQUIRE NEW PROPERTIES AT ATTRACTIVE PRICES OR TO SUCCESSFULLY DEVELOP OUR PROPERTIES. We encounter strong competition from other oil and gas companies in acquiring properties and leases for the exploration, exploitation and production of oil and natural gas. Many of our competitors have financial resources, staff and facilities substantially greater than ours. Our competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. As a result, we may not be able to buy properties at affordable prices or to successfully develop our properties. Our ability to explore, develop and exploit oil and natural gas reserves and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. WE ARE SUBJECT TO GOVERNMENT REGULATION AND LIABILITY, INCLUDING ENVIRONMENTAL LAWS THAT COULD REQUIRE SIGNIFICANT EXPENDITURES AND COULD MATERIALLY DECREASE OUR NET INCOME. The exploration, development, exploitation, production and sale of oil and natural gas in the U.S. are subject to many federal, state and local laws and regulations, including environmental laws and regulations. Under these laws and regulations, we may be required to make large expenditures that could materially and adversely affect our results of operations. These expenditures could include payments for personal injuries, property damage, oil spills, the discharge of hazardous materials, remediation and clean-up costs and other environmental damages. While we maintain insurance coverage for our operations, we do not believe that full insurance coverage for all potential environmental damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Laws and regulations protecting the environment have become increasingly stringent in recent years and may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be liable for the conduct of others or for our own acts even if our acts complied with applicable laws at the time we performed those acts. RISKS RELATING TO OUR COMMON STOCK IF WE DO NOT MAINTAIN THE LISTING OF OUR COMMON STOCK ON THE NASDAQ NATIONAL MARKET OR ANY OTHER STOCK EXCHANGE, THE PRICE OF THE COMMON STOCK MAY BE DEPRESSED AND YOU MAY HAVE DIFFICULTIES RESELLING THE STOCK. On October 26, 2000, our common stock was listed for trading on the Nasdaq National Market under the trading symbol "DVXE." In order to maintain our listing on the National Market we must continue to meet certain minimum net tangible asset base, minimum market capitalization and minimum trading price thresholds. Failure to maintain the listing of our common stock on the Nasdaq National Market or any other stock exchange could negatively affect the liquidity and marketability of the common stock. We were delisted from the Nasdaq Small Cap Market on November 11, 1999 due to our failure to satisfy certain listing requirements. IF THERE IS A CHANGE OF CONTROL OF THE COMPANY, WE WOULD BE IN DEFAULT UNDER OUR CREDIT AGREEMENT AND WE COULD BE REQUIRED TO REPURCHASE OUR SENIOR NOTES. If there is a change of control of our company as defined in our credit agreement, we would be in default under our credit agreement. In addition, the indenture governing our senior notes contains provisions that, under some circumstances, will cause our senior notes to become due upon the occurrence of a change of control as defined in the indenture. If a change of control occurs, we may not have the financial resources to repay this indebtedness and would be in default under the indenture. These provisions could also make it more difficult for a third party to acquire control of us, even if that change of control might benefit our stockholders. OUR CERTIFICATE OF INCORPORATION CONTAINS PROVISIONS THAT COULD DISCOURAGE AN ACQUISITION OR CHANGE OF CONTROL OF OUR COMPANY. Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. Provisions of our certificate of incorporation, such as the provision allowing our board of directors to issue 21 24 preferred stock with rights more favorable than our common stock, could make it more difficult for a third party to acquire control of us, even if that change of control might benefit our stockholders. OUR STOCKHOLDERS MAY EXPERIENCE SUBSTANTIAL DILUTION IN THE FUTURE Our board of directors may issue shares of common stock and preferred stock in the future which may dilute our stockholders' ownership. We are authorized to issue 100,000,000 shares of common stock (12,748,612 shares were issued and outstanding at March 15, 2001). We are also authorized to issue 50,000,000 shares of preferred stock (no shares of preferred stock were issued and outstanding at March 15, 2001). FUTURE SALES OF OUR COMMON STOCK MAY ADVERSELY AFFECT THE MARKET PRICE Future sales by stockholders could adversely affect the prevailing market price of our common stock. As of March 15, 2001 we had 12,748,612 shares of common stock outstanding. Of the issued and outstanding shares of our common stock, 12,016,112 are freely tradable without restriction or further registration under the Securities Act of 1933. The remaining 732,500 issued and outstanding shares of common stock are subject to contractual restrictions which limits the quantity that can be sold at any given time. These contractual restrictions will expire on April 30, 2001. ITEM 2. DESCRIPTION OF PROPERTIES GENERAL We occupy approximately 8,360 square feet of office space at 13760 Noel Road, Suite 1030, Dallas, Texas, under a lease that expires in October 2003. We also occupy approximately 2,000 square feet of space in Ottawa, Ontario for offices for certain of our executive officers located there under a lease that expires in August 2003. We lease property for a rig yard in New Mexico. OTHER For a description of our oil and natural gas properties, oil and natural gas reserves, acreage, wells, production and drilling activity, see "Item 1. Business." ITEM 3. LEGAL PROCEEDINGS The landowner royalty on the J.C. Martin field is currently the subject of a lawsuit that has created uncertainty regarding our title to our interest in the J.C. Martin field. For a description of this litigation, see "Item 1. Business - Risk Factors - Risks Related to Our Business - We may lose title to our royalty interest in the J.C. Martin field as a result of litigation over title to the royalty interest." No other legal proceedings are pending other than ordinary routine litigation incidental to us, the outcome of which management believes will not have a material adverse effect on our financial condition or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS During the last 3 months of the fiscal year ended December 31, 2000, no matter was submitted by us to a vote of our stockholders through the solicitation of proxies or otherwise. 22 25 PART II ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED STOCKHOLDER MATTERS MARKET INFORMATION Our common stock has been listed for trading on the Nasdaq National Market System under the trading symbol "DVXE" since October 26, 2000. From November 11, 1999 to October 26, 2000 our stock was quoted on the Nasdaq OTC Bulleting Board under the trading symbol "QSRI." From May 1997 to November 10, 1999 our common stock was quoted on the Nasdaq Small Cap Market under the symbol "QSRI." See "Item 1. Business - Risk Factors - Risks Relating to Our Common Stock." The following table sets forth the high and low closing bid prices for our common stock as reported on Nasdaq Small Cap Market, quoted on the OTC Bulletin Board or listed on the Nasdaq National Market for the periods indicated, and the prices before October 26, 2000 have been adjusted to give effect to the 156-to-1 reverse stock split of our common stock. We have no shares of preferred stock outstanding.

HIGH LOW ------- ------- YEAR ENDED DECEMBER 31, 1999 First Quarter $643.50 $175.50 Second Quarter $229.16 $146.17 Third Quarter $146.33 $ 43.84 Fourth Quarter $ 92.66 $ 43.84 FISCAL YEAR ENDED DECEMBER 31, 2000 First Quarter $ 82.68 $ 43.84 Second Quarter $ 63.38 $ 14.63 Third Quarter $ 46.32 $ 7.32 Fourth Quarter $ 8.38 $ 7.32

TRANSFER AGENT The Transfer Agent for our common stock is Continental Stock Transfer & Trust Company, 2 Broadway, New York, New York 10004. HOLDERS The approximate number of record holders of our common stock as of March 15, 2001 was 4,338, inclusive of those brokerage firms and/or clearing houses holding our common stock for their clientele (with each such brokerage house and/or clearing house being considered as one holder). CAPITAL STOCK ISSUANCES During the three months ended December 31, 2000, we issued 12,748,612 shares of post reverse-split common stock. Of this amount, 732,500 shares were issued pursuant to Section 3(a) (9) of the Securities Act of 1933, for no additional consideration to stockholders who exchanged all their outstanding preferred stock, warrants or repricing rights, 516,112 shares were issued pursuant to Section 3(a) (9) of the Securities Act of 1933 to the holder of pre reverse split common stock in exchange for their shares and 11,500,000 shares were issued pursuant to the Registration Statement on Form S-2 filed with the Securities and Exchange Commission under file number 333-41992 and declared effective on October 25, 2000. The company also issued a total of 642,500 options to its employees on October 27, 2000 under the company's 1997 Incentive Equity Plan. The exercise price of these options is $7.00 per optioned share. A total of 490,000 of these options vest in two equal annual installments beginning on October 27, 2001 and the remaining 152,500 options vest in three equal annual installments beginning on October 27, 2001. The company also issued a total of 90,000 options to its directors under the Directors' Non-Qualified Stock Option Plan. The exercise price of 9,000 of these Non-Qualified options is $7.00 per optioned share and the exercise price of the remaining 81,000 options is $7.0625 per optioned share. The options issued under the Directors' Non-Qualified Stock Option Plan will vest immediately upon stockholder approval. All 732,500 options were issued subject to stockholder approval of amendments to the plans. 23 26 DIVIDENDS We have never declared or paid any dividends on our common stock. We currently intend to retain future earnings, if any, for the operation and development of our business and do not intend to pay any dividends on our common stock in the foreseeable future. Because DevX Energy, Inc. is a holding company, our ability to pay dividends depends on the ability of our subsidiaries to pay cash dividends or make other cash distributions. Our credit agreement prohibits us from paying cash dividends on our common stock and the senior notes indenture restricts our payment of dividends on common stock. Our board of directors has sole discretion over the declaration and payment of future dividends subject to Delaware corporate law. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time and will depend on our profitability, financial condition, cash requirements, future prospects, general business conditions, the terms of our debt agreements and certificate of incorporation and other factors our board of directors believes relevant. 24 27 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth for the periods indicated certain of our summary historical consolidated financial information. The summary historical consolidated financial information for each of the years in the five years ended December 31, 2000 have been derived from our audited consolidated financial statements. During 2000, we changed our year end from June 3 to December 31. The information in the table below has been presented on a calendar year basis. We completed material acquisitions of producing properties in some of the periods presented which affects the comparability of the historical financial and operating data for all periods presented. The summary historical information below should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results and Operations," our Consolidated Financial Statements and the notes thereto.

YEAR ENDED DECEMBER 31 ------------------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- --------- --------- --------- (IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA) OPERATIONS DATA: Oil and natural gas sales(1) $ 42,205 $ 30,354 $ 27,832 $ 5,950 $ 3,030 Oil and natural gas production expenses(1) 7,941 6,408 10,292 3,600 1,650 --------- --------- --------- --------- --------- Net oil and natural gas revenues 34,264 23,946 17,540 2,350 1,380 General and administrative expenses 4,497 3,629 2,420 2,120 1,080 --------- --------- --------- --------- --------- EBITDA(2) 29,767 20,317 15,120 230 300 Hedge contract termination costs -- 3,328 -- -- -- Interest and financing costs(3) 15,659 16,949 11,735 1,110 770 Depletion, depreciation, and amortization(4) 10,242 11,056 11,433 1,400 840 Ceiling test write-down(5) -- -- 63,199 -- -- Interest and other income (90) (357) (156) (310) (70) Unrealized losses on derivative contracts 1,945 -- -- -- -- Income tax benefit (642) -- -- -- -- --------- --------- --------- --------- --------- Income (loss) from continuing operations $ 2,653 $ (10,659) $ (71,091) $ (1,970) $ (1,240) ========= ========= ========= ========= ========= Income (loss) per common share ($/share)(6) Basic $ 1.12 $ (49.52) $ (414.90) $ (11.49) $ (7.80) ========= ========= ========= ========= ========= Diluted $ 0.87 $ (49.52) $ (414.90) $ (11.49) $ (7.80) ========= ========= ========= ========= ========= CASH FLOWS DATA: Net cash provided by (used in) in operating $ 6,514 $ 693 $ 8,377 $ (520) $ (400) activities Net cash provided by (used in) investing (9,573) 2,036 (163,584) (10,090) (6,750) activities Net cash provided by (used in) financing 10,668 (2,392) 155,131 12,830 7,810 activities Net increase (decrease) in cash 7,609 337 (76) 2,210 650

AT DECEMBER 31 ------------------------------------------------------------- 2000 1999 1998 1997 1996 --------- --------- --------- --------- --------- BALANCE SHEET DATA (AT END OF PERIOD): Total current assets $ 21,725 $ 8,562 $ 8,475 $ 4,512 $ 1,390 Property and equipment, net 97,091 95,982 107,966 26,085 11,080 Deferred assets 4,174 8,074 12,060 13 -- Total assets 122,990 112,618 128,501 30,610 12,470 Total current liabilities 9,014 11,926 10,203 3,765 6,130 Long-term obligations, net of current 50,000 134,106 136,294 7,281 2,600 portion Derivatives 12,246 -- -- -- -- Total stockholders' equity (deficit) 51,730 (33,414) (17,996) 19,564 3,740

--------- (1) Oil and natural gas sales and production expenses related to net profits interests have been presented as if such net profits interests were working interests. (2) EBITDA represents earnings before interest expense, income taxes, depreciation, depletion and amortization expense, hedge contract termination costs, write-down of oil and natural gas properties and extraordinary items and excludes interest and other income. EBITDA is not a measure of income or cash flows in accordance with generally accepted accounting principles, but is presented as a supplemental financial indicator as to our ability to service or incur debt. EBITDA is not presented as an indicator of cash available for discretionary spending or as a measure of liquidity. EBITDA may not be comparable to other similarly titled measures of other companies. Our credit agreement requires the maintenance of specified EBITDA ratios. EBITDA should not be considered in isolation or as a substitute for net income, operating cash flow or any other measure of financial performance prepared in accordance with generally accepted accounting principles or as a measure of our profitability or liquidity. (3) Interest charges payable on outstanding debt obligations. (4) Depreciation, depletion and amortization includes amortized deferred charges related to debt obligations of $1.6 million for the year ended December 31, 2000, and $1.5 million for the year ended December 31, 1999, and $0.5 million for the year ended December 31, 1998. (5) In accordance with the full cost method of accounting, the results of operations for the year ended December 31, 1998 include a write-down of oil and natural gas properties of $63,199,000. (6) Per share amounts have been retroactively adjusted to reflect the effect of a reverse stock split of one common share for every 156 shares of our common stock. 25 28 We did not pay any cash dividends during any of the periods presented. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL We are an independent energy company engaged in the exploration, development, exploitation and acquisition of oil and natural gas properties in on-shore, known producing areas, using conventional recovery techniques. Our goal is to expand our reserve base, cash flow and net income and to generate an attractive return on capital. Our strategy to achieve these goals consists of these elements: o develop, exploit and explore our existing oil and natural gas properties; o identify acquisition opportunities that complement our existing properties; and o utilize a well balanced financial structure that will allow us to direct the cash generated from operations to fund production and reserve growth without having to be overly reliant on the capital markets. We use the full cost method of accounting for our investment in oil and natural gas properties. Under this method, we capitalize all acquisition, exploration and development costs incurred for the purpose of finding and developing oil and natural gas reserves, including salaries, benefits and other related general and administrative costs directly attributable to these activities. We capitalized general and administrative costs of $1,287,000 in the fiscal year ended December 31, 1998, $813,000 in the fiscal year ended December 31, 1999 and $691,000 in the fiscal year ended December 31, 2000. We expense costs associated with production and general corporate activities in the period incurred. We capitalize interest costs related to unproved properties and properties under development. Sales of oil and natural gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless these adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. The following table sets forth certain operating information for the periods presented. Information is presented as if the net profits interests had been accounted for as working interests. The three periods are not readily comparable because we acquired and disposed of certain producing oil and natural gas producing properties during some of the periods presented. More specifically, during April 1998, we acquired the net profits interests. During the summers of 1999 and 2000, we sold some of our producing properties.

YEAR ENDED DECEMBER 31 -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- PRODUCTION DATA: Natural gas (Mcf) 9,797,000 11,441,000 9,931,000 Oil (Bbls) 216,000 339,000 481,000 Mcfe 11,096,000 13,474,000 12,814,000 AVERAGE SALES PRICE, NET OF CASH SETTLEMENTS ON HEDGES: Natural gas ($/Mcf) $ 3.69 $ 2.24 $ 2.16 Oil ($/Bbl) 27.89 14.05 13.26 Mcfe ($Mcfe) 3.80 2.25 2.17 AVERAGE COST ($/MCFE) DATA: Production and operating costs $ 0.55 $ 0.39 $ 0.66 Production and severance taxes 0.16 0.08 0.15 General and administrative costs 0.41 0.27 0.19 Interest expense (excluding amortization of deferred debt issuance costs) 1.41 1.26 0.92 Depletion, depreciation, and amortization (excluding write-down of oil and natural gas properties) 0.77 0.68 0.79

26 29 The following discussion of the results of operations and financial condition should be read in conjunction with our consolidated financial statements and related notes thereto included herein, and reflects the operating results as if the net profits interests were accounted for as working interests. We believe that this presentation will provide the reader with a more meaningful understanding of the underlying operating results and conditions for the period. THE YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999 RESULTS OF OPERATIONS REVENUES. Total revenues during the year ended December 31, 2000 were $42.2 million, an increase of $11.8 million from the $30.4 million for the year ended December 31, 1999. Our revenues were derived from the sale of 9.8 Bcf of natural gas at an average price per Mcf of $3.69 and 216,000 barrels of oil at an average price per barrel of $27.89. During the year ended December 31, 1999 our revenues were derived from the sale of 11.4 Bcf of natural gas, at an average price per Mcf of $2.24, and 339,000 barrels of oil, at an average price per barrel of $14.05. Overall we produced 11.1 Bcfe at an average price of $3.80 per Mcfe during the year ended December 31, 2000 as compared to 13.5 Bcfe at an average price of $2.25 per Mcfe during the year ended December 31, 1999. This represents a decrease of 2.4 Bcfe (18%) in production and an increase of $1.55 (69%) in the average price we received. We produced 216,000 barrels of oil during the year ended December 31, 2000, a decrease of 123,000 barrels (36%) from the 339,000 barrels produced during the comparable period in 1999. The properties that we sold during 1999 represent 92,000 barrels (75%) of the total decrease of 123,000 barrels. Production from the properties that we owned during both periods decreased by 31,000 barrels. This represents a 13% decline from volumes produced during the year ended December 31, 1999. The decrease in production of oil from the properties owned during the comparative periods is comprised of two components: o The Segno field has not been meeting production expectations. This under performance represents approximately 77% of the decrease in production from the properties that we owned during both periods. Some of the capital projects planned for 2000 were not carried out by the operator of the property. We have agreed to join with the operator in farming out certain Middle Wilcox rights in the property. o The final component of the production decline is the result of the natural depletion of our oil reservoirs. We produced 9.8 Bcf of natural gas during the year ended December 31, 2000, down from the 11.4 Bcf produced during the comparable period in 1999. The properties that we sold during 1999 represent 0.4 Bcf (27%) of the total decrease of 1.6 Bcf. Production from the properties that we owned during both periods decreased by 1.2 Bcf. This represents an 11% decline from the volumes produced during the year ended December 31, 1999. The decrease in natural gas production from the properties owned during the comparative periods is comprised of three components: o The Gilmer field declined approximately 14% from the prior year which represents 42% of the decrease in production from the properties that we owned during both periods. The operator of the property commenced a drilling program during mid-year 2000. By December 31, 2000, five new wells had been drilled and four of those had been placed on production with average initial production rates of 815 Mcf per well, net to our interest. o The Lopeno and Volpe fields natural gas production was down 65% from 1999, or 47% of the total decrease in production from properties that we owned during both periods. As of June 20, 2000 we sold approximately one-half of our interest in the property, which accounts for approximately 20% of the reduction. In addition, during the fourth quarter, one new well was unsuccessful and a workover did not achieve expected results. We believe that meaningful development and exploitation potential remains in these properties. o The final component of the production decline is the result of the natural depletion of our natural gas reservoirs. 27 30 On a billion cubic feet of gas equivalent ("Bcfe") basis, production for the year ended December 31, 2000 was 11.1 Bcfe, down 2.4 Bcfe (18%) from the 13.5 Bcfe produced during the comparable period in 1999. The properties that we sold at the end of June 1999 represent 1.0 Bcfe of the total decrease of 2.4 Bcfe. Production from the properties that we owned during both periods decreased by 1.4 Bcfe. The decrease in revenues resulting from lower production volumes was offset by the significant industry-wide increase in oil and natural gas prices. The average price per barrel of oil sold by us during the year ended December 31, 2000 was $27.89, an increase of $13.84 per barrel (99%) over the $14.05 per barrel during the year ended December 31, 1999. The average price per Mcf of natural gas sold by us was $3.69 during the year ended December 31, 2000, an increase of $1.45 per Mcf (65%) over the $2.24 per Mcf during the comparable period in 1999. Oil prices have remained at these elevated levels subsequent to December 31, 2000. Natural gas prices were volatile throughout the year, and have remained so subsequent to December 31, 2000. On an Mcfe basis, the average price received by us during the year ended December 31, 2000 was $3.80, a $1.55 increase (69%) over the $2.25 we received during the comparable period in 1999. During the year ended December 31, 2000 we paid $203,000 in cash settlements pursuant to our oil price-hedging program. The effect on the average oil prices we received during the period was a decrease of $0.94 per barrel (3%). During the year ended December 31, 2000 we paid $3,317,000 in cash settlements and amortized $44,000 of deferred hedging costs regarding our natural gas price-hedging program. The net negative effect on the average natural gas prices we received during the period was $0.35 (9%). Payments made as a result of our oil price-hedging program during the year ended December 31, 1999 were $592,000, which reduced our average oil price by $1.75 per barrel (12%). During 1999 we received $643,000 in cash settlements and amortized $120,000 of deferred hedging costs regarding our natural gas price-hedging program. The net positive effect on the average natural gas prices we received during the period was $0.06 per Mcf (3%). COSTS AND EXPENSES. Operating costs and expenses for the year ended December 31, 2000, exclusive of the effect of mark-to-market accounting for derivative contracts used to hedge oil and natural gas prices, were $38.3 million. Of this total, lease operating expenses and production taxes were $7.9 million, general and administrative expenses were $4.5 million, interest charges were $17.3 million and depletion, depreciation and amortization costs were $8.6 million. Operating costs and expenses for the year ended December 31, 1999, exclusive of a $3.3 million hedge contract termination payment and the $1.1 million extraordinary loss from the write-down of deferred charges when we replaced our operating loans, were $38.0 million. Of this total, lease operating expenses and production taxes were $6.4 million, general and administrative expenses were $3.6 million, interest charges were $18.6 million and depletion, depreciation and amortization costs were $9.4 million. Severance and production taxes, which are based on the revenues derived from the sale of oil and natural gas, were $1.8 million during the year ended December 31, 2000, as compared to $1.1 million during 1999, an increase of $700,000, or 63%. The increase is primarily as a result of increased wellhead revenues. On a cost per Mcfe basis, severance taxes were $0.16 per Mcfe for the year ended December 31, 2000 compared to $0.08 per Mcfe for the comparable period ending December 31, 1999, an increase of 100%. The increase in our average wellhead prices, which rose by 83%, from $2.25 per Mcfe during the year ended December 31, 1999 to $4.12 per Mcfe during 2000, caused the increase in per unit severance taxes. Our lease operating expenses grew to $6.1 million for the year ended December 31, 2000, an increase of $0.8 million, or 16%, from the $5.3 million incurred during the comparable period in 1999. The increase had three primary causes. We receive periodic rebates related to processing costs in our Gilmer property. These rebates, which reduce our total processing costs, were higher in 1999 than 2000, due to timing of payments during 1999 and lower plant throughput during 2000. During a portion of 1999, we shut-in several oil producing properties, in response to depressed crude oil prices, in order to reduce total costs. Those properties were back on production for the full year during 2000. Finally, these two increases were offset by the effect of costs related to properties we sold during 1999. Lease operating expenses were $0.55 per Mcfe during the year ended December 31, 2000, an increase of $0.16, or 41%, from the $0.39 per Mcfe incurred during the comparable period in 1999. This increase in average costs per Mcfe is a result of increased total costs being spread over lower production volumes. 28 31 General and administrative expenses were $4.5 million for 2000 compared to $3.6 million incurred during 1999. This increase of $868,000 (24%) consists primarily of costs related to severance payments and certain staffing changes, approximately $740,000 of which are non-recurring costs. On a per unit basis, general and administrative expenses for the year ended December 31, 2000 were $0.41 per Mcfe, an increase of $0.14 per Mcfe (52%) from the $0.27 per Mcfe incurred during the year ended December 31, 1999. This per unit increase in general and administrative expenses is a result of our increased total expenses spread over a decreased level of oil and natural gas production. Interest expense for the year ended December 31, 2000 was $17.3 million. This was comprised of $15.7 million paid or payable in cash and $1.6 million of amortization of deferred costs incurred at the time that the related debt obligations were incurred. During the year ended December 31, 1999 our interest expense was $18.6 million. This was comprised of $16.9 million paid or payable in cash and $1.7 million of amortized deferred debt issuance costs incurred at the time that the related debt obligations were established. Interest expense was reduced slightly as a result of a reduction of our debt during the fourth quarter of 2000 in connection with our recapitalization. On a per unit basis, cash interest expense for the year ended December 31, 2000 was $1.41 per Mcfe, as compared to $1.26 per Mcfe during 1999. This is the result of the 18% reduction in production we had during 2000, as compared to 1999, offset by slightly reduced interest expense for 2000 compared to 1999. The decrease in depletion, depreciation and amortization costs of $0.8 million was a result of the 18% decrease in the volume of oil and natural gas produced by us during the year ended December 31, 2000 as compared to the year ended December 31, 1999. On a cost per Mcfe of reserves, the depletion, depreciation and amortization costs increased by $0.09 per Mcfe (13%). This increase is a function of higher unamortized capitalized costs for 2000 and a reduction in total reserve quantities. INCOME TAX BENEFIT. As a result of our recapitalization in October 2000, we were able to recognize the expected future benefits of utilizing a portion of our net operating loss carryforwards to offset taxes payable in future years. As a result, we reported a net tax benefit in income approximating $0.6 million during 2000. EXTRAORDINARY GAIN (LOSS). In October 2000 we completed a public offering of our stock and used a portion of the proceeds to repurchase $75 million face value of our 12.5% senior notes for $52.5 million. In connection with this recapitalization, we recorded an extraordinary gain of $21.1 million. In October 1999 we replaced our old credit agreement with our new credit agreement. As a result, we wrote off $1.1 million in unamortized deferred debt issuance costs associated with the old credit agreement. CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND CHANGE IN FAIR VALUE OF DERIVATIVES. Effective July 1, 2000, we adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, or SFAS 133, which requires us to recognize all derivatives on the balance sheet at fair value. Upon adoption of SFAS 133, we had four open derivative contracts, one of which has been designated as a hedge. At adoption, we recognized a derivative liability and a reduction in other comprehensive income of approximately $5.5 million as a cumulative effect of accounting change for the derivative contract designated as a hedge. In connection with the other three derivative contracts, we recognized a net derivative asset of approximately $0.6 million and a related gain of approximately $0.4 million in the income statement as a cumulative effect of accounting change. During the six months ended December 31, 2000, we recognized a non-cash loss of approximately $1.9 million in earnings related to the net change in the fair value of our derivative contracts which have not been designated as hedges. NET INCOME. For the year ended December 31, 2000, we recorded net income of $24.2 million or $10.24 per basic share ($7.96 per diluted share), compared to a loss of $11.8 million, or $54.76 per basic and diluted share, for 1999. The reduction of debt and increased natural gas prices are the primary causes of the significantly improved results. 29 32 THE YEAR ENDED DECEMBER 31, 1999 COMPARED TO THE YEAR ENDED DECEMBER 31, 1998 RESULTS OF OPERATIONS REVENUES. Total revenues during the year ended December 31, 1999 were $30.4 million, an increase of $2.5 million from the $27.8 million for 1998. Our revenues were derived from the sale of 11.4 Bcf of natural gas at an average price per Mcf of $2.24 and 339,000 barrels of oil at an average price per barrel of $14.05. During 1998, our revenues were derived from the sale of 9.9 Bcf of natural gas, at an average price per Mcf of $2.16, and 481,000 barrels of oil, at an average price per barrel of $13.26. Overall we produced 13.5 Bcfe at an average price of $2.25 per Mcfe during 1999 as compared to 12.8 Bcfe at an average price of $2.17 per Mcfe during 1998. This represents an increase of 0.7 Bcfe (5%) in production and an increase of $0.08 (4%) in the average price we received. We produced 339,000 barrels of oil during the year ended December 31, 1999, a decrease of 142,000 barrels (29%) from the 481,000 barrels produced during 1998. The properties that we sold during 1999 represent 115,000 barrels (81%) of the total decrease of 141,000 barrels. Production from the properties that we owned during both periods decreased by 27,000 barrels. This represents a 10% decline from volumes produced during the year ended December 31, 1998. The decrease in production of oil from the properties owned during the comparative periods is comprised of three components: o During March 1999, we shut in substantially all of the wells in the Caprock field in New Mexico in response to low oil prices. As oil prices recovered late in 1999, we returned to production those wells that produce economically. o As an offset to the total decrease in oil volumes, production from our net profits interests, which were acquired during April 1998, were up during 1999, reflecting a full year's production from those properties. o The final component of the production decline is the result of the natural depletion of our oil reservoirs. o We produced 11.4 Bcf of natural gas during 1999, up from the 9.9 Bcf produced during 1998. The increase is primarily a reflection of a full year's production from our net profits interests, which were acquired during April 1998. The total increase was offset by properties that we sold during 1999, which resulted in reduced gas volumes of 0.6 Bcf. On a billion cubic feet of gas equivalent ("Bcfe") basis, production for 1999 was 13.5 Bcfe, up 0.7 Bcfe (5%) from the 12.8 Bcfe produced during 1998. A full year's production during 1999 from the net profits interest properties generated increased volumes of 2.1 Bcfe. Offsetting the increase, the properties that we sold at the end of June 1999 represent a reduction of 1.3 Bcfe. The average price per barrel of oil sold by us during 1999 was $14.05, an increase of $0.79 per barrel (6%) over the $13.26 per barrel realized during 1998. The average price per Mcf of natural gas sold by us was $2.24 during 1999, an increase of $0.08 per Mcf (4%) over the $2.16 per Mcf received during 1998. On an Mcfe basis, the average price received by us during 1999 was $2.25, a $0.08 increase (4%) over the $2.17 we received during 1998. During the year ended December 31, 1999 we paid $592,000 in cash settlements pursuant to our oil price-hedging program. The effect on the average oil prices we received during the period was a decrease of $1.75 per barrel (12%). During 1999, we received 643,000 in cash settlements and amortized $108,000 of deferred hedging costs regarding our natural gas price-hedging program. The net positive effect on the average natural gas prices we received during the period was $0.06 (3%). Payments received as a result of our oil price-hedging program during 1998 were $380,000, which increased our average oil price by $0.79 per barrel (6%). During 1998, we also received $803,000 in cash settlements and amortized $89,000 of deferred hedging costs regarding our natural gas price-hedging program. The net positive effect on the average natural gas prices we received during the period was $0.08 per Mcf (4%). COSTS AND EXPENSES. Operating costs and expenses for the year ended December 31, 1999, exclusive of a $3.3 million hedge contract termination payment and the $1.1 million extraordinary loss from the write-down of deferred charges when we replaced our operating loans, were $38.0 million. Of this total, lease operating expenses and 30 33 production taxes were $6.4 million, general and administrative expenses were $3.6 million, interest charges were $18.6 million and depletion, depreciation and amortization costs were $9.4 million. Operating costs and expenses for the year ended December 31, 1998, exclusive of an extraordinary charge of $3.5 million, were $35.8 million. Of this total, lease operating expenses and production taxes were $10.3 million, general and administrative expenses were $2.4 million, interest charges were $12.2 million and depletion, depreciation and amortization costs were $10.9 million. Severance and production taxes, which are based on the revenues derived from the sale of oil and natural gas, were $1.1 million during 1999, compared to $1.9 million during 1998, a decrease of $800,000, or 42%. These taxes amounted to approximately 4% of wellhead revenues during 1999, down from 7% of wellhead revenues during 1998. The reduction is a result of the substantial changes in our property base resulting from the acquisition of the net profits interests during 1998 and the sale of certain properties during 1999, coupled with the fact that two significant net profits interests receive severance tax abatements. On a cost per Mcfe basis, severance taxes were $0.08 per Mcfe for the year ended December 31, 1999, compared to $0.15 per Mcfe for 1998, a decrease of 47%. The change in our property base mentioned above more than offsets the effect of slightly higher wellhead prices received during 1999 over 1998. Our lease operating expenses fell to $5.3 million for the year ended December 31, 1999, a decrease of $3.1 million, or 37%, from the $8.4 million incurred during 1998. The decrease had three primary causes. We sold certain properties during June 1999, eliminating the costs associated with operating those properties. We receive periodic rebates related to processing costs in our Gilmer property. These rebates, which reduce total net processing costs, were higher in 1999 than 1998 due to timing of payments during 1999. During a portion of 1999, we shut-in several oil producing properties, in response to depressed crude oil prices, in order to reduce total costs. Lease operating expenses were $0.39 per Mcfe during 1999, a decrease of $0.27, or 41%, from the $0.66 per Mcfe incurred in 1998. This improvement is primarily the result of lower total costs, as discussed above. General and administrative expenses increased $1.2 million over 1998, primarily as a result of our increased payroll costs, higher occupancy costs related to our move into larger offices and increased professional fees. On a per unit basis, general and administrative expenses for 1999 were $0.27 per Mcfe, up $0.08 from the $0.19 per Mcfe for 1998. This per unit increase in general and administrative expenses is a result of our increased total costs. Interest expense for 1999 was $18.6 million, an increase of $6.4 million, or 52%, over the $12.2 million recorded during 1998. The increase reflects the increased borrowings incurred in connection with our purchase of the net profits interests during April 1998. On a per unit basis, cash interest expense was $1.26 per Mcfe during 1999, as compared to $0.92 per Mcfe for 1998. This is a result of our total cash interest expense increasing at a faster rate than our growth in production volumes. Depletion, depreciation and amortization costs decreased $1.4 million during 1999 primarily as a result of the significant reduction in unamortized costs during 1998, related to a non-cash write-down of $63 million we recorded during 1998. On a cost per Mcfe of reserves the depletion, depreciation and amortization costs decreased by $0.11 per Mcfe (14%). EXTRAORDINARY LOSS. In October 1999 we replaced our old credit agreement with our new credit agreement. As a result, we wrote off $1.1 million in unamortized deferred debt issuance costs associated with the old credit agreement. In July 1998, we unwound a LIBOR interest rate swap contract at a cost of $3.5 million. NET LOSS. We incurred a loss of $11.8 million, or $54.76 per basic share, for the year ended December 31, 1999 compared to $74.6 million, or $435.61 per basic share for the year ended December 31, 1998. The decline in oil and natural gas prices between December 31, 1997 and December 31, 1998 caused us to record non-cash write-downs of oil and natural gas properties of $63 million during 1998. 31 34 LIQUIDITY AND CAPITAL RESOURCES GENERAL We completed a recapitalization on October 31, 2000. See "Item 1. Business - Recent Developments." The key components of the recapitalization were: (a) a reverse stock split of one common share for every 156 shares of our common stock; (b) the exchange of all preferred stock then outstanding, all warrants exercisable for shares of common stock and all unexercised common stock repricing rights for 732,500 shares of post reverse-split common stock; and (c) the repurchase of $75 million face value of our senior notes for approximately $52.5 million. In addition we completed a public offering of 11,500,000 shares of post reverse-split common stock generating net proceeds to us after deducting underwriters' discounts and offering expenses of approximately $73.1 million. The net proceeds were used to finance the repurchase of our senior notes, repay bank debt of approximately $14 million and fund working capital. Our board of directors decided to effect a quasi-reorganization given the infusion of new equity capital, the reduction in debt, changes in management and changes in the our operations. Accordingly, our accumulated deficit as of the date of the recapitalization, $68.1 million, was eliminated against additional paid-in capital. The historical carrying values of our assets and liabilities were not adjusted in connection with the quasi-reorganization. As of March 15, 2001, under our credit agreement we: o had no indebtedness outstanding; o had $8.5 million reserved to secure a letter of credit; and o were permitted to borrow an additional $35 million. Our general financial strategy is to use cash flow from operations, debt financings and the issuance of equity securities to service interest on our indebtedness, to pay ongoing operating expenses, and to contribute toward the further development of our existing proved reserves as well as additional acquisitions. There can be no assurance that cash from operations will be sufficient in the future to cover all such purposes. We have planned exploration, development and exploitation activities for all of our major operating areas. We plan to spend $25 million to $27 million in capital activities during 2001, with 15 percent to 35 percent of that allocated to exploration activities. We believe our cash flow from operations combined with our existing credit facility will be sufficient to fund our planned exploration, development and exploitation activities. In addition, we are continuing to evaluate oil and natural gas properties for future acquisition. Historically, we have used the proceeds from the sale of our securities in the private equity market and borrowings under our credit facilities to raise cash to fund acquisitions or repay indebtedness incurred for acquisitions, and we have also used our securities as a medium of exchange for other companies assets in connection with acquisitions. However, there can be no assurance that such funds will be available to us to meet our budgeted capital spending. Furthermore, our ability to borrow other than under the credit agreement is subject to restrictions imposed by the credit agreement and the indenture governing our senior notes. If we cannot secure additional funds for our planned development and exploitation activities, then we will be required to delay or reduce substantially both of such activities. SOURCES OF CAPITAL We have a credit agreement with Ableco Finance LLC and Foothill Capital Corporation which allows for borrowings of up to $50 million, subject to borrowing base limitations, from such lenders to fund, among other things, development and exploitation expenditures, acquisitions and general working capital. Our borrowing base under the credit agreement is currently $43.5 million, none of which was outstanding as of March 15, 2001. Under the credit agreement we have provided a first lien on all of our assets to secure our obligations under the agreement. The credit 32 35 agreement matures on April 22, 2003. There are no scheduled principal repayments. The credit agreement bears interest as follows: o when the borrowings are less than $30 million or borrowings are less than 67% of the borrowing base as defined in the agreement, bank prime plus 2%; o when the borrowings are $30 million or greater and borrowings exceed 67% of the borrowing base as defined in the agreement, bank prime plus 3.5%; o on amounts securing letters of credit issued on our behalf, 3%. The credit agreement contains certain affirmative and negative financial and operating covenants, including maintaining an interest coverage ratio greater than one, a minimum of 1.5-to-1 working capital ratio (calculated as set set out in the credit agreement) and a $30 million annual limit on capital spending. At December 31, 2000, the Company exceeded the capital spending limitation, for which the lender issued a waiver. The credit agreement was amended during January 2001 to increase the capital spending limitation, and we believe the new limit is sufficient to accommodate our plans for 2001. We have a letter of credit outstanding under the credit agreement in the amount of $8.5 million, as of March 15, 2001, to an affiliate of Enron to secure a swap exposure. This letter of credit has the effect of reducing our credit availability under the credit agreement. In October and November 2000 we completed a public offering of 11,500,000 shares of post reverse-split common stock generating net proceeds to us after deducting underwriters' discounts and offering expenses of approximately $73.1 million. The net proceeds were used to finance the repurchase of $75 million original principal amount of our senior notes for approximately $52.5 million, to repay approximately $14 million then outstanding under the credit agreement and to fund working capital. We have implemented a commodity gas price hedging program that provides a degree of protection against significant decreases in oil and gas prices. The interest payable under our senior notes is fixed at 12.5%. If we incur debt under the Abelco credit agreement, the interest expense will be variable. We may not have sufficient liquidity or capital to undertake all acquisition prospects which we may wish to pursue. Therefore, we will continue to be dependent on raising substantial amounts of additional capital through any one or a combination of institutional or bank debt financing, equity offerings, debt offerings and internally generated cash flow, or by forming sharing arrangements with industry participants. Although we have been able to obtain such financings and to enter into such sharing arrangements in certain of our projects to date, there can be no assurance that we will continue to be able to do so. Alternatively, we may consider issuing additional securities in exchange for producing properties. There can be no assurance that any such financings or sharing arrangement can be obtained. Further acquisitions and development activities in addition to those for which we are contractually obligated are discretionary and depend to a significant degree on cash availability from outside sources such as bank debt and the sale of securities or properties. USES OF CAPITAL During the period since our inception in August 1994 through April 1998, our primary method of replacing our production and increasing our reserves was through acquisitions. Since that time, our primary method of replacing production and enhancing our reserves was through the development and exploitation of our oil and natural gas properties. We have recently entered into two exploration joint ventures and expect to allocate 15 percent to 35 percent of our 2001 capital spending to exploration activities. We expect to spend between $25 million and $27 million on discretionary capital expenditures during 2001 for exploitation, development and exploration projects. We believe that cash flow from operations and our credit agreement will be sufficient to fund our planned activities. However, our cash flow from operations is significantly affected by the uncertainty of commodity prices. If there were a significant decline in prices, we would evaluate our projects and may delay or defer some of our planned activities. As of March 1, 2001, we are contractually obligated to fund $6.7 million in capital expenditures through December 2001. 33 36 INFLATION During the past several years, we have experienced some inflation in oil and natural gas prices with moderate increases in property acquisition and development costs. During the fiscal year ended December 31, 2000, we received higher commodity prices for the natural resources produced from our properties than we did during the year ended December 31, 1999. Our results of operations and cash flow have been, and will continue to be, affected to a certain extent by the volatility in oil and natural gas prices. Should we experience a significant increase in oil and natural gas prices that is sustained over a prolonged period, we could expect that there would also be a corresponding increase in oil and natural gas finding costs, lease acquisition costs, and operating expenses. CHANGES IN PRICES AND HEDGING ACTIVITIES Annual average oil and natural gas prices have fluctuated significantly over the last two years. The table below sets out our weighted average price per barrel of oil and the weighted average price per Mcf of natural gas, the impact of our hedging programs and the related NYMEX indices.

DECEMBER 31 -------------------------- 2000 1999 1998 ------ ------ ------ NATURAL GAS (PER MCF): Price received at wellhead $ 4.04 $ 2.18 $ 2.08 Effect of hedge contracts (0.35) (0.06) 0.08 ------ ------ ------ Effective price received, including hedge contracts 3.69 2.24 2.16 Average NYMEX Henry Hub 3.91 2.27 2.14 Average basis differential excluding hedge contracts 0.13 (0.09) (0.06) Average basis differential including hedge contracts (0.22) (0.03) 0.02 OIL (PER BARREL): Average price received at wellhead per barrel 28.83 15.80 12.47 Average effect of hedge contract (0.94) (1.75) 0.79 ------ ------ ------ Average price received, including hedge contracts 27.89 14.05 13.26 Average NYMEX Sweet Light Oil 30.20 19.24 14.46 Average basis differential excluding hedge contracts (1.37) (3.44) (1.99) Average basis differential including hedge contracts (2.31) (5.19) (1.20)

We have a commodity price risk management or hedging strategy that is designed to provide protection from low commodity prices while providing some opportunity to enjoy the benefits of higher commodity prices. We have a series of natural gas futures contracts with various counter-parties. This strategy is designed to provide a degree of protection from negative shifts in natural gas prices as reported on the Henry Hub Nymex Index. For the year ending December 31, 2001, we have 8.7 Bcf hedged at a weighted average floor price of $3.00/Mcf and 5.0 Bcf hedged with a weighted average ceiling price of $5.38/Mcf. The table below sets out the volume of natural gas that remains under contract with the Bank of Montreal at a floor price of $2.00 per MMBtu. The volumes set out in this table are divided equally over the months during the period:

Volume Period Beginning Period Ending (MMBtu) ---------------- ------------- ------- January 1, 2001 December 31, 2001 2,970,000 January 1, 2002 December 31, 2002 2,550,000 January 1, 2003 December 31, 2003 2,250,000

34 37 The table below sets out volume of natural gas hedged with a floor price of $1.90 per MMBtu with Enron. The volumes presented in this table are divided equally over the months during the period:

Volume Period Beginning Period Ending (MMBtu) ---------------- ------------- ------- January 1, 2001 December 31, 2001 740,000 January 1, 2002 December 31, 2002 640,000 January 1, 2003 December 31, 2003 560,000

The table below sets out volume of natural gas hedged with a swap at $2.40 per MMBtu with Enron. The volumes presented in this table are divided equally over the months during the period:

Volume Period Beginning Period Ending (MMBtu) ---------------- ------------- ------- January 1, 2001 December 31, 2001 1,850,000 January 1, 2002 December 31, 2002 1,600,000 January 1, 2003 December 31, 2003 1,400,000

The table below sets out the volume of natural gas and floor and ceiling prices hedged with Texaco. The volumes presented in this table are divided equally over the months during the period:

Volume Floor Ceiling Period Beginning Period Ending (MMBtu) Price Price ---------------- ----------------- --------- ----- ------- January 1, 2001 March 31, 2001 1,125,000 $5.44 $8.29 April 1, 2001 June 30, 2001 675,000 $4.07 $6.42 July 1, 2001 December 31, 2001 1,350,000 $4.07 $6.51 January 1, 2002 December 31, 2002 900,000 $4.00 $6.75

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK HEDGES OF OIL AND NATURAL GAS PRODUCTION To reduce our exposure to changes in the prices of oil and natural gas, we have entered into and may in the future enter into arrangements to hedge our oil and natural gas production, whereby gains and losses in the fair value of the derivative instruments are generally offset by price changes in the underlying commodity. The hedges that we have entered into generally provide a `floor' or `cap and floor' on the prices paid for our oil and natural gas production over a period of time. Hedging arrangements may expose us to the risk of financial loss in some circumstances, including the following: o our production does not meet the minimum production requirements under the agreement; o the other party to the hedging contract defaults on its contract obligations; or o there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. 35 38 Due to our risk assessment procedures and internal controls, we believe that the use of these derivative instruments does not expose us to material risk, however, the use of derivative instruments for the hedging activities could affect our results of operations in particular quarterly or annual periods. The use of these instruments limits the downside risk of adverse price movements, but it may also limit our ability to benefit from favorable price movements. Our hedging strategy is designed to provide protection from low commodity prices while providing some opportunity to enjoy the benefits of higher commodity prices. We have a series of natural gas futures contracts with Bank of Montreal, an affiliate of Enron and Texaco. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Changes in Prices and Hedging Activities" for a complete description of our hedging positions. As of December 31, 2000 the fair value of our hedging contracts, measured as the estimated cost we would incur to terminate the arrangements, was $13.5 million. As of December 31, 2000 a 10% increase in oil and natural gas prices would have resulted in an unfavorable change of $3.3 million in the fair value of our hedging contracts and a 10% decrease in oil and natural gas prices would have resulted in a favorable change of $3.3 million in the fair value of our hedging contracts. INTEREST RATES At December 31, 2000, our exposure to interest rates relates primarily to borrowings under our credit agreement. As of December 31, 2000, we are not using any derivatives to manage interest rate risk. Interest is payable on borrowings under the credit agreement based on a floating rate. As of December 31, 2000, and as of March 15, 2001, we have no amounts borrowed under our credit agreement. Our excess cash balances are invested in short-term money market instruments at floating rates. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA For the Financial Statements required by Item 8, see the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There are no changes or disagreements required to be reported under this Item 9. 36 39 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item will be set forth under the captions "Election of Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Executive Officers" of our proxy statement for our 2000 Annual Meeting of Stockholders (the "Proxy Statement") which will be filed with the Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 (the "Exchange Act") and is incorporated herein by reference. The Proxy Statement is expected to be filed on or prior to April 30, 2001. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is set forth under the caption "Executive Compensation" of our Proxy Statement, which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is set forth under the caption "Security Ownership of Certain Beneficial Owners and Management" of our Proxy Statement which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is set forth under the captions "Executive Compensation," " Director Compensation" and "Certain Relationships and Related Party Transactions" of our Proxy Statement which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. 37 40 GLOSSARY The terms defined in this glossary are used throughout this Form 10-K. "average NYMEX price." The average of the NYMEX closing prices for the near month. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bbl/d. Bbl per day. Bcf. One billion cubic feet of natural gas. Bcfe. One billion cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of gas. "behind-the-pipe." Hydrocarbons in a potentially producing horizon penetrated by a well bore the production of which has been postponed pending the production of hydrocarbons from another formation penetrated by the well bore. The hydrocarbons are classified as proved but non-producing reserves. "development well." A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive. "dry well." A development or exploratory well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. "exploratory well." A well drilled to find oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir. "gross acres" or "gross wells." The total number of acres or wells, as the case may be, in which a working interest is owned. MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. Mcf. One thousand cubic feet of natural gas. Mcf/d. Mcf per day. Mcfe. One thousand cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of gas. MMBbl. One million barrels of crude oil or other liquid hydrocarbons. MMcfe. One million cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of gas. MMcf. One million cubic feet of natural gas. "Morgan Properties" means the net profits interests and royal interest revenues we purchased in April 1998 from pension funds managed by J.P. Morgan Investments. "net acres" or "net wells." The sum of the fractional working interests owned in gross acres or gross wells. "net profits interest." A share of the gross oil and natural gas production from a property, measured by net profits from the operation of the property, that is carved out of the working interest. This is a non-operating interest. 38 41 "non-producing reserves." Non-producing reserves consist of (i) reserves from wells that have been completed and tested but are not yet producing due to lack of market or minor completion problems that are expected to be corrected, and (ii) reserves currently behind-the-pipe in existing wells which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the well. NYMEX. New York Mercantile Exchange. "producing well," "production well" or "productive well." A well that is producing oil or natural gas or that is capable of production. "proved developed producing." Proved developed producing reserves are proved developed reserves which are currently capable of producing in commercial quantities. "proved developed reserves." Proved developed reserves are oil and natural gas reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. "proved reserves." The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. "proved undeveloped reserves" or PUD. Proved undeveloped reserves are oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery techniques is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. "recompletion." A recompletion is an operation to abandon the production of oil and/or natural gas from a well in one zone within the existing wellbore and to make the well produce oil and/or natural gas from a different, separately producible zone within the existing wellbore. "Reserve Life Index." The estimated productive life of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this Form 10-K, reserve life is calculated by dividing the proved reserves (on a Mcfe basis) at the end of the period by production volumes for the previous 12 months. "royalty interest." An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of costs of production. "SEC PV-10." The present value of proved reserves is an estimate of the discounted future net cash flows from each of the properties at December 31, 2000, or as otherwise indicated. Net cash flow is defined as net revenues less, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. As required by rules of the Commission, the future net cash flows have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with Commission rules, estimates have been made using constant oil and natural gas prices and operating costs, at December 31, 2000, or as otherwise indicated. 39 42 "secondary recovery." A method of oil and natural gas extraction in which energy sources extrinsic to the reservoir are utilized. "service well." A well used for water injection in secondary recovery projects or for the disposal of produced water. "Standardized Measure." Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pretax cash inflows over the Company's tax basis in the associated properties. Tax credits, net operating loss carryforwards, and permanent differences are also considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure. "undeveloped acreage." Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. "working interest." The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. 40 43 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) (1) FINANCIAL STATEMENTS See Index to Consolidated Financial Statements following the signature page to this Annual Report on Form 10-K. (a) (2) FINANCIAL STATEMENT SCHEDULES All Schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in the Consolidated Financial Statements or related notes. (a) (3) EXHIBITS 3.1 Restated Certificate of Incorporation of the Company, filed as Exhibit 4.5 to the Company's Registration Statement on Form S-3 (No. 333-47577) filed with the Securities and Exchange Commission on March 9, 1998, which Exhibit is incorporated herein by reference 3.2 Certificate of Designation of Series C Convertible Preferred Stock of the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated December 24, 1997, which Exhibit is incorporated herein by reference. 3.3 Certificate of Amendment to the Restated Certificate of Incorporation of the Company, filed with the Secretary of State for the State of Delaware on September 19, 2000 which Certificate was filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated herein by reference. 3.4* Certificate of Amendment to the Restated Certificate of Incorporation of the Company, filed with the Secretary of State for the State of Delaware on October 26, 2000, which Certificate is filed herewith. 3.5 Amended and Restated Bylaws of the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 27, 1997, which Exhibit is incorporated herein by reference. 4.1 Indenture, dated July 1, 1998, in regard to 12 1/2% Senior Notes due 2008 by and among the Company and certain of its subsidiaries and Harris Trust and Savings Bank, as Trustee, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, which Exhibit is incorporated herein by reference. 4.2* First Supplement to Indenture dated October 12, 2000 among the Company, certain of its subsidiaries and Harris Trust and Savings Bank as Trustee, which Exhibit is filed herewith. 4.3 Settlement Agreement dated as of July 17, 2000 between the Company and the stockholders named therein, filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated herein by reference. 4.4 Participation Agreement dated as of July 17, 2000 between the Company and the holders of its 12 1/2% senior notes therein filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992) which Exhibit is incorporated herein by reference. 4.5 Amendment to Participation Agreement dated as of October 4, 2000 between the Company and certain holders of its 12 1/2% senior notes therein filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated herein by reference 10.1 Queen Sand Resources 1997 Incentive Equity Plan, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998, which Exhibit is incorporated herein by reference. 10.2* Form of DevX Energy, Inc. Restated and Amended Incentive Equity Plan filed herewith**. 10.3* Form of Option Agreement issued under the Amended and Restated Incentive Equity Plan filed herewith**. 41 44 10.4 Directors' Non-Qualified Stock Option Plan filed as Appendix A to the Company's Definitive Proxy Statement on Schedule 14A dated October 23, 1998, which Exhibit is incorporated herein by reference**. 10.5* Form of DevX Energy, Inc. Restated and Amended Directors' Non-Qualified Stock Option Plan filed herewith**. 10.6* Form of Option Agreement issued under the Amended and Restated Directors' Non-Qualified Stock Option Plan filed herewith**. 10.7 Amended and Restated Credit Agreement among the Company, DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, effective as of October 22, 1999, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.8 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by the Company as Guarantor in favor of Ableco Finance LLC, as Collateral Agent for the lender group and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.9 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by DevX Operating Company a Nevada corporation, (formerly known as Queen Sand Operating Co.), as Guarantor, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.10 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Corrida Resources, Inc. as Guarantor, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.11 Security Agreement dated as of October 22, 1999, by and among the Company, DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), DevX Operating Company (formerly known as Queen Sand Operating Co.), Corrida Resources, Inc. and Ableco Finance LLC, as collateral agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.12 Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.13 Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by the Company in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.14 Amendment No. 1 to Credit Agreement dated May 2000 among the Company, DevX Energy, Inc., a Nevada corporation (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 (No. 333-41992), which Exhibit is incorporated by reference. 10.15 Amendment No. 2 to Credit Agreement dated June 30, 2000 among the Company, DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000, (No. 333-41992), which Exhibit is incorporated by reference. 10.16 Amendment No. 3 to Credit Agreement dated September , 2000 among the Company, DevX Energy, Inc., a Nevada corporation (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, 42 45 as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated by reference. 10.17 Amendment No. 4 to Credit Agreement dated October 24, 2000 among the Company, DevX Energy, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, which Exhibit is incorporated by reference. 10.18* Amendment No. 5 to Credit Agreement dated January 31, 2001 among the Company, DevX Energy, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, which Amendment is filed herewith. 10.19* Employment Agreement dated as of October 6, 2000 between the Company and Joseph T. Williams which agreement is filed herewith**. 10.20* Form of Directors' Indemnity Agreement signed by Jerry B. Davis and Robert L. Keiser.** 10.21 Employment Agreement dated December 15, 1997 between the Company and Robert P. Lindsay, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference**. 10.22* Release Agreement dated December 7, 2000 between the Company and Robert P. Lindsay which agreement is filed herewith**. 10.23 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Bruce I. Benn, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference**. 10.24* Release Agreement dated December 7, 2000 between the Company and Bruce I. Benn which agreement is filed herewith**. 10.25 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Ronald Benn, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference**. 10.26 Release Agreement dated September 15, 2000 between the Company and Ronald I. Benn filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated by reference**. 10.27* Employment Agreement dated as of November 10, 2000 between the Company and Edward J. Munden which agreement is filed herewith**. 10.28* Employment Agreement dated as of November 10, 2000 between the Company and William W. Lesikar which agreement is filed herewith**. 10.29* Employment Agreement dated as of November 10, 2000 between the Company and Brian J. Barr which agreement is filed herewith**. 21.1 List of the subsidiaries of the registrant filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1999 (No. 333-61403) which Exhibit is incorporated by reference. 23.1* Consent of Ernst & Young LLP. 23.2* Consent of Ryder Scott Company. 23.3* Consent of H.J. Gruy and Associates, Inc. ----------- * Indicates filed herewith. ** Indicates management contract 43 46 (b) REPORTS ON FORM 8-K During the last quarter of the fiscal year ended December 31, 2000, the Company filed the following reports: (i) A Current Report on Form 8-K, dated November 29, 2000 pursuant to Item 5 with respect to the sale of 1,500,000 shares of the Company's common stock pursuant to the exercise of an underwriters' over-allotment option. (ii) A Current Report on Form 8-K, dated November 10, 2000 pursuant to Item 5 with respect to the appointment of Patrick J. Keeley to the Board of Directors, and pursuant to Item 8 with respect to a change in fiscal year-end to December 31, 2000 and pursuant to Item 9 regarding an estimate of SEC PV-10 reserve value as of September 30, 2000. (c) FINANCIAL STATEMENT SCHEDULE AND AUDITORS' REPORT. No other financial statement schedules are filed as part of this Form 10-K since the required information is included in the financial statements, including the notes thereto, or circumstances requiring the inclusion of such schedules are not present. 44 47 SIGNATURE PAGE 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 ON THE 30TH DAY OF MARCH, 2001. DEVX ENERGY, INC. By: /s/ EDWARD J. MUNDEN ------------------------------------- Name: Edward J. Munden Title: Chief Executive Officer and President PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT IN THE CAPACITIES INDICATED ON THE 30TH DAY OF MARCH 2001.

SIGNATURE TITLE --------- ----- /s/ JOSEPH T. WILLIAMS CHAIRMAN OF THE BOARD -------------------------- JOSEPH T. WILLIAMS /s/ EDWARD J. MUNDEN PRESIDENT, CHIEF EXECUTIVE -------------------------- OFFICER AND DIRECTOR EDWARD J. MUNDEN (PRINCIPAL EXECUTIVE OFFICER) /s/ WILLIAM W. LESIKAR CHIEF FINANCIAL OFFICER (PRINCIPAL -------------------------- FINANCIAL OFFICER AND ACCOUNTING OFFICER) WILLIAM W. LESIKAR /s/ ROBERT L. KEISER DIRECTOR -------------------------- ROBERT L. KEISER /s/ JERRY B. DAVIS DIRECTOR -------------------------- JERRY B. DAVIS /s/ PATRICK J. KEELEY DIRECTOR -------------------------- PATRICK J. KEELEY

45 48 DEVX ENERGY, INC. AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE ---- Report of Ernst & Young LLP, Independent Auditors.......................... F-2 Consolidated Financial Statements Consolidated Balance Sheets as of December 31, 2000 and 1999............... F-3 Consolidated Statements of Operations for the Years ended December 31, 2000, 1999 and 1998.......................... F-4 Consolidated Statements of Stockholders' Equity (Net Capital Deficiency) for the Years ended December 31, 2000, 1999 and 1998...... F-5 Consolidated Statements of Cash Flows for the Years ended December 31, 2000, 1999 and 1998.......................... F-7 Notes to Consolidated Financial Statements................................. F-8

49 REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS The Board of Directors and Stockholders DevX Energy, Inc. We have audited the accompanying consolidated balance sheets of DevX Energy, Inc. and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity (net capital deficiency), and cash flows for each of the three years in the period ended December 31, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 DevX Energy, Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. As discussed in Note 1 to the consolidated financial statements, effective July 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." Dallas, Texas March 1, 2001 F-2 50 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

DECEMBER 31 ------------------------------ 2000 1999 ------------- ------------- ASSETS Current assets: Cash $ 10,985,000 $ 3,376,000 Accounts receivable 10,557,000 4,727,000 Other 183,000 459,000 ------------- ------------- Total current assets 21,725,000 8,562,000 ------------- ------------- Property and equipment, at cost: Oil and gas properties, based on full cost accounting method 191,204,000 181,549,000 Other equipment 446,000 402,000 ------------- ------------- 191,650,000 181,951,000 Less accumulated depreciation and amortization (94,559,000) (85,969,000) ------------- ------------- Net property and equipment 97,091,000 95,982,000 Other assets 2,953,000 8,074,000 Deferred tax asset 1,221,000 -- ------------- ------------- $ 122,990,000 $ 112,618,000 ============= ============= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable $ 1,004,000 $ 2,328,000 Accrued liabilities 6,503,000 8,721,000 Current portion of long-term obligations -- 877,000 Derivatives 1,507,000 -- ------------- ------------- Total current liabilities 9,014,000 11,926,000 Long-term obligations, net of current portion 50,000,000 134,106,000 Derivatives 12,246,000 -- Commitments and contingencies Stockholders' equity (net capital deficiency): Preferred stock, $0.01 par value: Authorized shares - 50,000,000 at December 31, 2000 and 1999 Issued and outstanding shares - 0 and 9,604,248 at December 31, 2000 and 1999, respectively -- 96,000 Aggregate liquidation preference - $0 and $9,678,000 at December 31, 2000 and 1999, respectively Common stock, $0.234 par value: Authorized shares - 100,000,000 at December 31, 2000 and 1999 Issued and outstanding shares - 12,748,612 and 236,960 at December 31, 2000 and 1999, respectively 2,983,000 70,000 Additional paid-in capital 60,159,000 64,945,000 Retained earnings (deficit) ($68,130,000 of accumulated deficit eliminated in the quasi-reorganization of October 31, 2000) 834,000 (91,274,000) Accumulated other comprehensive loss (12,246,000) Treasury stock, at cost -- (7,251,000) ------------- ------------- Total stockholders' equity (net capital deficiency) 51,730,000 (33,414,000) ------------- ------------- Total liabilities and stockholders' equity $ 122,990,000 $ 112,618,000 ============= =============

See accompanying notes. F-3 51 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS

YEAR ENDED DECEMBER 31 -------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ Revenues: Oil and gas sales $ 4,484,000 $ 3,625,000 $ 5,852,000 Net profits and royalty interests 31,507,000 21,955,000 15,947,000 Interest and other 90,000 345,000 156,000 ------------ ------------ ------------ Total revenues 36,081,000 25,925,000 21,955,000 ------------ ------------ ------------ Expenses: Production expenses 1,727,000 1,622,000 4,326,000 Depreciation and amortization 8,637,000 9,418,000 10,866,000 Hedge contract termination costs -- 3,328,000 -- Write-down of oil and gas properties -- -- 63,199,000 General and administrative 4,497,000 3,629,000 2,420,000 ------------ ------------ ------------ Total expenses 14,861,000 17,997,000 80,811,000 ------------ ------------ ------------ Operating income (loss) 21,220,000 7,928,000 (58,856,000) Other expenses: Interest and financing costs 17,264,000 18,587,000 12,235,000 Change in fair value of derivatives 1,945,000 -- -- ------------ ------------ ------------ Income (loss) before income taxes, extraordinary items, and cumulative effect of accounting change 2,011,000 (10,659,000) (71,091,000) Income tax benefit 642,000 -- -- ------------ ------------ ------------ Income (loss) before extraordinary items and cumulative effect of accounting change 2,653,000 (10,659,000) (71,091,000) Extraordinary gain (loss), net of tax 21,144,000 (1,130,000) (3,549,000) ------------ ------------ ------------ Income (loss) before cumulative effect of accounting change 23,797,000 (11,789,000) (74,640,000) Cumulative effect of accounting change, net of tax 413,000 -- -- ------------ ------------ ------------ Net income (loss) $ 24,210,000 $(11,789,000) $(74,640,000) ============ ============ ============ Basic income (loss) per share amounts: Income (loss) before cumulative effect of accounting change and extraordinary items $ 1.12 $ (49.52) $ (414.90) Extraordinary gain (loss) 8.94 (5.24) (20.71) ------------ ------------ ------------ Income (loss) before cumulative effect of accounting change 10.06 (54.76) (435.61) Cumulative effect of accounting change 0.18 -- -- ------------ ------------ ------------ Net income (loss) $ 10.24 $ (54.76) $ (435.61) ============ ============ ============ Diluted income (loss) per shares amounts: Income (loss) before cumulative effect of accounting change and extraordinary items $ 0.87 $ (49.52) $ (414.90) Extraordinary gain (loss) 6.95 (5.24) (20.71) ------------ ------------ ------------ Income (loss) before cumulative effect of accounting change 7.82 (54.76) (435.61) Cumulative effect of accounting change 0.14 -- -- ------------ ------------ ------------ Net income (loss) $ 7.96 $ (54.76) $ (435.61) ============ ============ ============ Weighted average shares outstanding: Basic 2,364,817 215,268 171,344 Diluted 3,041,386 215,268 171,344

See accompanying notes. F-4 52 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (NET CAPITAL DEFICIENCY) YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998

PREFERRED STOCK COMMON STOCK ADDITIONAL ---------------------------- --------------------------- PAID-IN SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 1997 9,610,400 $ 96,000 144,395 $ 48,000 $ 29,020,000 $ (5,000,000) Issuance of common stock for oil and gas properties -- -- 2,219 1,000 1,751,000 -- Issuance of common stock for cash -- -- 34,013 8,000 26,972,000 -- Issuance of common stock upon exercise of warrants -- -- 15,860 4,000 6,996,000 -- Issuance of common stock pursuant to repricing rights -- -- 4,984 1,000 (1,000) -- Issuance of common stock on conversion of convertible preferred stock (2,290) -- 2,534 -- -- -- Issuance of common stock as stock dividend -- -- 111 -- 98,000 -- Repurchase of convertible preferred stock (2,152) -- -- -- -- (2,251,000) Net loss -- -- -- -- -- -- ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 1998 9,605,958 96,000 204,116 62,000 64,836,000 (7,251,000) Issuance of common stock pursuant to repricing rights -- -- 19,245 5,000 (5,000) -- Issuance of common stock on conversion of convertible preferred stock (1,710) -- 12,642 3,000 (3,000) -- Issuance of common stock as stock dividend -- -- 957 -- 117,000 -- Net loss -- -- -- -- -- -- ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 1999 9,604,248 $ 96,000 236,960 $ 70,000 $ 64,945,000 $ (7,251,000)

ACCUMULATED OTHER RETAINED TOTAL COMPREHENSIVE EARNINGS STOCKHOLDERS' LOSS (DEFICIT) EQUITY ------------ ------------ ------------ Balance at December 31, 1997 $ -- $ (4,630,000) $ 19,534,000 ------------ ------------ ------------ Issuance of common stock for oil and gas properties -- -- 1,752,000 Issuance of common stock for cash -- -- 26,980,000 Issuance of common stock upon exercise of warrants -- -- 7,000,000 Issuance of common stock pursuant to repricing rights -- -- -- Issuance of common stock on conversion of convertible preferred stock -- -- -- Issuance of common stock as stock dividend -- (98,000) -- Repurchase of convertible preferred stock -- -- (2,251,000) Net loss -- (74,640,000) (74,640,000) ------------ ------------ ------------ Balance at December 31, 1998 -- (79,368,000) (21,625,000) Issuance of common stock pursuant to repricing rights -- -- -- Issuance of common stock on conversion of convertible preferred stock -- -- -- Issuance of common stock as stock dividend -- (117,000) -- Net loss -- (11,789,000) (11,789,000) ------------ ------------ ------------ Balance at December 31, 1999 $ -- $(91,274,000) $(33,414,000)

F-5 53 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (CONTINUED) (NET CAPITAL DEFICIENCY) YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998

PREFERRED STOCK COMMON STOCK ADDITIONAL ---------------------------- --------------------------- PAID-IN SHARES AMOUNT SHARES AMOUNT CAPITAL TREASURY ------------ ------------ ------------ ------------ ------------ ------------ Issuance of common stock for cash -- $ -- 11,498,878 $ 2,691,000 $ 70,421,000 $ -- Issuance of common stock pursuant to repricing rights -- -- 628,962 147,000 (147,000) -- Issuance of common stock on conversion of convertible preferred stock (9,604,248) (96,000) 378,519 89,000 7,000 -- Issuance of common stock as stock dividend -- -- 5,293 1,000 231,000 -- Retire treasury stock -- -- -- (15,000) (7,236,000) 7,251,000 Reclassification of accumulated deficit pursuant to quasi-reorganization -- -- -- -- (68,130,000) -- Other -- -- -- -- 68,000 -- Net income -- -- -- -- -- -- Cumulative effect of accounting change -- -- -- -- -- -- Unrealized losses on derivatives -- -- -- -- -- -- Comprehensive income -- -- -- -- -- -- ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 2000 -- $ -- $ 12,748,612 $ 2,983,000 $ 60,159,000 $ -- ============ ============ ============ ============ ============ ============

ACCUMULATED OTHER RETAINED TOTAL COMPREHENSIVE EARNINGS STOCKHOLDERS' LOSS (DEFICIT) EQUITY ------------ ------------ ------------ Issuance of common stock for cash $ -- $ -- $ 73,112,000 Issuance of common stock pursuant to repricing rights -- -- -- Issuance of common stock on conversion of convertible preferred stock -- -- -- Issuance of common stock as stock dividend -- (232,000) -- Retire treasury stock -- -- -- Reclassification of accumulated deficit pursuant to quasi-reorganization -- 68,130,000 -- Other -- -- 68,000 Net income 24,210,000 24,210,000 Cumulative effect of accounting change (5,515,000) -- (5,515,000) Unrealized losses on derivatives (6,731,000) -- (6,731,000) Comprehensive income -- -- (11,964,000) ------------ ------------ ------------ Balance at December 31, 2000 $(12,246,000) $ 834,000 $ 51,730,000 ============ ============ ============

See accompanying notes. F-6 54 DEVX ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31 ----------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- OPERATING ACTIVITIES Income (loss) before extraordinary items and cumulative effect of change in accounting $ 2,653,000 $ (10,659,000) $ (71,091,000) Adjustments to reconcile income (loss) to net cash provided by operating activities: Deferred tax benefit (1,424,000) -- -- Depreciation and amortization 8,637,000 9,313,000 10,850,000 Amortization of deferred costs 1,605,000 1,242,000 738,000 Write-down of oil and gas properties -- -- 63,199,000 Change in market value of derivatives 1,945,000 -- -- Unrealized foreign currency translation gains (43,000) (131,000) -- Changes in operating assets and liabilities: Accounts receivable (5,830,000) 246,000 (3,660,000) Other assets 276,000 4,000 (379,000) Accounts payable and accrued liabilities (1,305,000) 678,000 8,720,000 ------------- ------------- ------------- Net cash provided by operating activities 6,514,000 693,000 8,377,000 INVESTING ACTIVITIES Additions to oil and gas properties (13,043,000) (7,494,000) (153,961,000) Proceeds from sales of oil and gas properties 3,386,000 10,236,000 -- Other 84,000 (706,000) (9,623,000) ------------- ------------- ------------- Net cash provided by (used in) investing activities (9,573,000) 2,036,000 (163,584,000) FINANCING ACTIVITIES Proceeds from revolving credit facilities 14,000,000 20,032,000 92,800,000 Debt issuance costs -- (1,130,000) -- Termination of LIBOR swap agreement -- -- (3,549,000) Payment on revolving credit facilities (23,106,000) (21,227,000) (87,671,000) Proceeds from issuance of 12.5% senior notes -- -- 125,000,000 Redemption of 12.5% senior notes (52,504,000) -- -- Redemption of DEM bonds (791,000) -- (1,206,000) Payments on notes payable -- -- (1,901,000) Proceeds from the issuance of common stock 73,112,000 -- 33,980,000 Repurchase of common and preferred stock -- -- (2,251,000) Payments on capital lease obligation (43,000) (67,000) (71,000) ------------- ------------- ------------- Net cash provided by (used in) financing activities 10,668,000 (2,392,000) 155,131,000 Net increase (decrease) in cash 7,609,000 337,000 (76,000) Cash at beginning of year 3,376,000 3,039,000 3,115,000 ------------- ------------- ------------- Cash at end of year $ 10,985,000 $ 3,376,000 $ 3,039,000 ============= ============= =============

See accompanying notes. F-7 55 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000, 1999 AND 1998 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL DevX Energy, Inc. (DEVX or the Company, formerly Queen Sand Resources, Inc.) was formed on August 9, 1994, under the laws of the State of Delaware. The Company is engaged in one industry segment: the acquisition, exploration, development, production and sale of crude oil and natural gas. The Company's business activities are carried out primarily in Kentucky, Oklahoma and Texas. Effective December 31, 2000, the Company changed its fiscal year end to December 31. The accompanying financial statements have been prepared on a calendar year for each period presented. PRINCIPLES OF CONSOLIDATION The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. PROPERTY AND EQUIPMENT The Company follows the full cost method of accounting for its oil and gas activities under which all costs, including general and administrative expenses directly associated with property acquisition, exploration and development activities, are capitalized. Capitalized general and administrative expenses directly associated with acquisitions, exploration and development of oil and gas properties were approximately $691,000, $813,000 and $1,287,000 for the years ended December 31, 2000, 1999 and 1998, respectively. Capitalized costs are amortized by the unit-of-production method using estimates of proved oil and gas reserves prepared by independent engineers. The costs of unproved properties are excluded from amortization until the properties are evaluated. Sales of oil and gas properties are accounted for as adjustments to the capitalized cost center unless such sales significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, in which case a gain or loss is recognized. The Company limits the capitalized costs of oil and gas properties, net of accumulated amortization, to the estimated future net revenues from proved oil and gas reserves less estimated future development and production expenditures discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, as adjusted for related estimated future tax effects. If capitalized costs exceed this limit (the full cost ceiling), the excess is charged to depreciation and amortization expense. During the year ended December 31, 1998, the Company recorded full cost ceiling write-downs of $63,199,000. Amortization of the capitalized costs of oil and gas properties and limits to capitalized costs are based on estimates of oil and gas reserves which are inherently imprecise and are subject to change based on factors such as crude oil and natural gas prices, drilling results, and the results of production activities, among others. Accordingly, it is reasonably possible that such estimates could differ materially in the near term from amounts currently estimated. Depreciation of other property and equipment is provided principally by the straight-line method over the estimated service lives of the related assets. Equipment under capital lease is recorded at the lower of fair value or the present value of future minimum lease payments and is depreciated over the lease term. Costs incurred to operate, repair and maintain wells and equipment are charged to expense as incurred. F-8 56 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Certain of the Company's oil and gas activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities. The Company does not expect future costs for site restoration, dismantlement and abandonment, postclosure, and other exit costs which may occur in the sale, disposal or abandonment of a property to be material. REVENUE RECOGNITION The Company uses the sales method of accounting for oil and gas revenues. Under the sales method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. ENVIRONMENTAL MATTERS The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, 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 or chemical 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 benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. INCOME TAXES Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred tax assets is adjusted by a valuation allowance, if necessary, to recognize the extent to which, based on available evidence, the future tax benefits more likely than not will be realized. STATEMENT OF CASH FLOWS The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. During 1998, the Company issued an aggregate of 2,219 shares of Common Stock valued at $1,752,000 in connection with the acquisition of certain interests in oil and gas properties. INCOME (LOSS) PER COMMON SHARE Basic income or loss per share is calculated based on the weighted average number of common shares outstanding during the period. If applicable, diluted earnings per share is calculated based on the weighted average number of common shares outstanding during the period plus any dilutive common equivalent shares outstanding. As the Company incurred net losses during each of the years ended December 31, 1999 and 1998, the loss per common F-9 57 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) share data is based on the weighted average common shares outstanding and excludes the effects of the Company's potentially dilutive securities (Note 6). The following table reconciles basic and diluted weighted average shares outstanding:

2000 1999 1998 --------- --------- --------- Basic weighted average shares 2,364,817 215,268 171,344 Dilutive effect of: Common stock repricing rights 673,627 -- -- Employee stock options 2,942 -- -- --------- --------- --------- Diluted weighted average shares 3,041,386 215,268 171,344 ========= ========= =========

Losses per common share for periods prior to the completion of the Company's recapitalization transaction (Note 2) have been restated for the effects of a 156-to-1 reverse stock split. STOCK COMPENSATION The Company has elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25), in accounting for its employee stock options. Under APB 25, if the exercise price of an employee's stock options equals or exceeds the market price of the underlying stock on the date of grant and certain other plan conditions are met, no compensation expense is recognized. In March 2000, the Financial Accounting Standards Board issued Interpretation No. 44, Accounting for Certain Transactions Involving Stock Compensation (FIN 44), an interpretation of APB 25. FIN 44, which was adopted prospectively by the Company as of July 1, 2000, requires certain changes to the previous practice regarding the accounting for certain stock compensation arrangements. FIN 44 does not change APB 25's intrinsic value method, under which compensation expense is generally not recognized for grants of stock options to employees with an exercise price equal to the market price of the stock at the date of grant, but it has narrowed its application. The adoption of FIN 44 did not have a significant effect on the Company's existing accounting for its employee stock options. CONCENTRATIONS OF RISK The Company sells crude oil and natural gas to various customers. In addition, the Company participates with other parties in the operation of crude oil and natural gas wells. Substantially all of the Company's accounts receivable are due from either purchasers of crude oil and natural gas or participants in crude oil and natural gas wells for which the Company serves as the operator. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company's receivables are generally unsecured. For the year ended December 31, 2000, four oil and gas companies accounted for 31%, 18%, 14% and 13%, respectively, of the Company's oil and gas sales. For the year ended December 31, 1999, four oil and gas companies accounted for 29%, 14%, 12% and 9%, respectively, of the Company's oil and gas sales. For the year ended December 31, 1998, three oil and gas companies accounted for 29%, 12% and 11%, respectively, of the Company's F-10 58 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) oil and gas sales. The Company does not believe that the loss of any of these buyers would have a material effect on the Company's business or results of operations as it believes it could readily locate other buyers. The Company's revenues and profitability are highly dependent upon the prevailing prices for oil and natural gas. As the Company produces more natural gas than oil, it faces more risk related to fluctuations in natural gas prices than oil prices. To reduce the exposure to changes in the price of oil and natural gas, the Company has entered into certain derivative contracts (Note 5). USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Because of the use of estimates inherent in the financial reporting process, actual results could differ from those estimates. COMPREHENSIVE INCOME Comprehensive income is defined as the change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. For the year ended December 31, 2000, the Company's comprehensive income differed from net income by approximately $12,246,000, due to the recognition in comprehensive income of unrealized losses related to certain of the Company's derivative instruments which have been designated as hedges. For the years ended December 31, 1999 and 1998, there were no differences between the Company's net losses and total comprehensive income. DERIVATIVES The Company utilizes certain derivative financial instruments, primarily swaps, floors and collars, to hedge future oil and gas prices. Effective July 1, 2000, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), which requires the Company to recognize all derivatives on the balance sheet at fair value. Prior to adoption of SFAS No. 133, gains and losses arising from the use of derivative instruments were deferred until realized. The Company estimates fair value based on quotes obtained from the counterparties to the derivative contracts. The Company recognizes the fair value of derivative contracts that expire in less than one year as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities. Derivatives that are not accounted for as hedges are adjusted to fair value through other income. If the derivative is a hedge, depending on the nature of the hedge, changes in fair value are either offset against the change in fair value of the hedged assets, liabilities, or firm commitments through earnings or recognized in other comprehensive income until the hedged item is recognized in earnings. Upon adoption of SFAS No. 133, the Company had four open derivative contracts. One contract, a natural gas swap, has been designated as a cash flow hedge. For derivatives classified as cash flow hedges, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of any change in the fair value of a derivative designated as a hedge is immediately recognized in earnings. Hedge effectiveness is measured quarterly based on the relative fair value between the derivative contract and the hedged F-11 59 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) item over time. At adoption, the Company recognized a derivative liability and a reduction in other comprehensive income of approximately $5,515,000 as a cumulative effect of accounting change for this cash flow hedge. During the six months ended December 31, 2000, the Company recognized an increase in the derivative liability and an associated other comprehensive loss totaling approximately $6,731,000. No amounts were recognized in earnings for hedging ineffectiveness during 2000. Additionally upon adoption, the Company recognized a net derivative asset of approximately $651,000 for the remaining three open derivative contracts, and a related gain of approximately $413,000 as a cumulative effect of accounting change in earnings. During the six months ended December 31, 2000, the Company recognized a loss of approximately $1,945,000 related to the net change in the fair value of derivative contracts which have not been designated as hedges. Gains and losses from settlements of hedges of oil and gas prices are reported as oil and gas sales. Gains and losses from settlements of interest rate hedges are reported in interest expense. 2. QUASI-REORGANIZATION On October 31, 2000, the Company completed a public offering of 10,000,000 shares of its common stock at a price per share to the public of $7.00. An additional 1,500,000 shares were sold during November 2000 upon the underwriter's exercise of its over-allotment option. The aggregate net proceeds to the Company (after deducting underwriter discount and expenses, and costs to repurchase fractional shares aggregating 1,122 shares of common stock) were approximately $73,112,000. Simultaneously with the closing of the October 31, 2000 offering, the Company completed a recapitalization transaction which included: (a) a reverse stock split of every 156 outstanding shares of common stock into one share; (b) the exchange of all preferred stock, all warrants exercisable for shares of common stock and all unexercised common stock repricing rights (Note 6) for 732,500 shares of post reverse-split common stock; (c) the repurchase of $75 million face value of 12.5% senior notes (Note 4) for $52,504,000; and (d) the Company used proceeds from the offering to pay down the balance on its revolving credit facility by $14 million ($11 million at closing and $3 million from the exercise of the over-allotment option) (the Recapitalization). The Company's board of directors decided to effect a quasi-reorganization given the infusion of new equity capital, the reduction in debt, changes in management and changes in the Company's operations. Accordingly, the Company's accumulated deficit as of the date of the Recapitalization, $68,130,000, was eliminated against additional paid-in capital. The historical carrying values of the Company's assets and liabilities were not adjusted in connection with the quasi-reorganization. Information presented for shares of common stock for all periods prior to the Recapitalization has been restated to retroactively reflect the effects of the reverse stock split. 3. NET PROFITS AND ROYALTY INTERESTS During 1998, the Company acquired certain nonoperated net profits interests and royalty interests (collectively, the Morgan Properties) from pension funds managed by J.P. Morgan Investments. The Company's interest in the Morgan Properties primarily takes the form of nonoperated net profits overriding royalty interests, whereby the Company is entitled to a percentage of the net profits from the operations of the properties. The oil and gas properties burdened by the Morgan Properties are primarily located in East Texas, South Texas and the mid-continent region of the United States. F-12 60 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 3. NET PROFITS AND ROYALTY INTERESTS (CONTINUED) Presented below are the oil and gas sales and associated production expenses associated with the Company's net profits and royalty interests, which are presented in the accompanying consolidated statements of operations for the years ended December 31, 2000, 1999 and 1998, respectively, as net profits and royalty interests revenues.

YEAR ENDED DECEMBER 31 --------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Oil and gas sales $37,721,000 $26,741,000 $21,913,000 Production expenses 6,214,000 4,786,000 5,966,000 ----------- ----------- ----------- Net profits and royalty interests $31,507,000 $21,955,000 $15,947,000 =========== =========== ===========

4. CURRENT AND LONG-TERM DEBT A summary of current and long-term debt follows:

DECEMBER 31 --------------------------- 2000 1999 ------------ ------------ 12.5% senior notes, due July 2008 $ 50,000,000 $125,000,000 12% unsecured DEM bonds, due July 2000 -- 834,000 Revolving credit agreement -- 9,106,000 Capital lease obligations -- 43,000 ------------ ------------ 50,000,000 134,983,000 Less current portion of debt and capitalized lease obligation -- 877,000 ------------ ------------ Total long-term obligations $ 50,000,000 $134,106,000 ============ ============

During October 1999, the Company entered into an amended and restated revolving credit agreement (the Credit Agreement) with new lenders. In connection with entering into the Credit Agreement, the Company retired borrowings under its previous credit agreement, terminating the arrangement. As a result, the Company recorded an extraordinary loss of $1,130,000 relating to the write-off of the unamortized deferred costs of the previous agreement. The Credit Agreement allows the Company to borrow up to $43.5 million (subject to borrowing base limitations). Borrowings under the Credit Agreement are secured by a first lien on the Company's oil and natural gas properties. Borrowings under the Credit Agreement bear interest at prime plus 2% on borrowings under $25 million and prime plus 4.5%, if borrowings exceed $25 million. There were no outstanding borrowings under the Credit Agreement at December 31, 2000. The interest rate at December 31, 2000, was 11.5%. The loan under the Credit Agreement expires on October 22, 2001. The Company is subject to certain affirmative and negative financial and operating covenants under the Credit Agreement, including maintaining a minimum interest coverage ratio, a minimum working capital ratio and certain limitations on capital spending. At December 31, 2000, the Company exceeded the capital spending limitation, for which the lender issued a waiver. Letters of credit up to a maximum of $12 million may be issued on behalf of the Company under the Credit Agreement, which bear interest at 3%. Any outstanding letters of credit reduce the Company's ability to borrow F-13 61 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 4. CURRENT AND LONG-TERM DEBT under the Credit Agreement. At December 31, 2000, the Company had a letter of credit outstanding in the amount of $8.5 million to secure a swap exposure (Note 5). Effective January 31, 2001, the Credit Agreement was amended to extend the maturity date to April 22, 2003, increase the capital spending limitation and modify the interest rate. Borrowings under the amended Credit Agreement bear interest as follows: when the borrowings are less than $30 million or borrowings are less than 67% of the borrowing base as defined in the agreement, bank prime plus 2%; when the borrowings are $30 million or greater and borrowings exceed 67% of the borrowing base as defined in the agreement, bank prime plus 3.5%; and on amounts securing letters of credit issued on our behalf, 3%. On July 8, 1998, the Company completed a private placement of $125,000,000 principal amount of 12.5% senior notes (the Notes) due July 1, 2008. Interest on the Notes is payable semiannually on January 1 and July 1 of each year, commencing January 1, 1999, at the rate of 12.5% per annum. The Notes are senior unsecured obligations of the Company and rank pari passu with any existing and future unsubordinated indebtedness of the Company. The Notes rank senior to all unsecured subordinated indebtedness of the Company. The Notes contain customary covenants that limit the Company's ability to incur additional debt, pay dividends and sell assets of the Company. Substantially all of the proceeds from the issuance of the Notes were used to retire indebtedness incurred in connection with the acquisition of the Morgan Properties. In connection with the Recapitalization, the Company retired $75,000,000 face amount of the Notes, recognizing an extraordinary gain of $21,144,000 (Note 2). The Company's payment obligations under the Notes are jointly, severally and unconditionally guaranteed by the Company's subsidiaries. The Company has no significant assets and no operations other than those conducted by its subsidiaries. No restrictions exist on the ability of the subsidiaries to make loans or pay dividends to the Company. Beginning in July 1995, the Company initiated private debt offerings whereby it could issue up to a maximum of 5,000,000 Deutschmark (DEM) denominated 12% notes due on July 15, 2000, of which DEM 1,600,000 were outstanding at December 31, 1999. During 2000, the Company retired all remaining outstanding notes for approximately $791,000. During the years ended December 31, 2000, 1999 and 1998, the Company made cash payments of interest totaling approximately $15,800,000, $16,402,000 and $3,953,000, respectively. 5. DERIVATIVES AND HEDGING ACTIVITIES The Company uses swaps, floors and collars to hedge oil and natural gas prices. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts quoted on the New York Mercantile Exchange (NYMEX). Generally, when the applicable settlement price is less than the price specified in the contract, the Company receives a settlement from the counterparty based on the difference multiplied by the volume hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, the Company pays the counterparty based on the difference. The Company generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally the Company receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap. F-14 62 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 5. DERIVATIVES AND HEDGING ACTIVITIES (CONTINUED) The Company had a collar with an affiliate of Enron Corp. (Enron), a stockholder of the Company, to hedge 50,000 MMBtu of natural gas production and 10,000 barrels of oil production monthly. The agreements, effective September 1, 1997, and terminating August 31, 1998, called for a natural gas and oil ceiling and floor price of $2.66 and $1.90 per MMBtu and $20.40 and $18.00 per barrel, respectively. During the year ended December 31, 1998, the Company recognized net hedging gains of approximately $233,000 relating to these agreements, which are included in oil and gas sales. The table below sets out volumes of natural gas hedged with a floor price of $1.90 per MMBtu with Enron, which received a fee of $478,000 during the year ended December 31, 1998 for entering into this agreement. The volumes presented in this table are divided equally over the months during the period.

VOLUME PERIOD BEGINNING PERIOD ENDING (MMBtu) ---------------- ----------------- --------- May 1, 1998 December 31, 1998 885,000 January 1, 1999 December 31, 1999 1,080,000 January 1, 2000 December 31, 2000 880,000 January 1, 2001 December 31, 2001 740,000 January 1, 2002 December 31, 2002 640,000 January 1, 2003 December 31, 2003 560,000

The table below sets out volumes of natural gas hedged with a swap at $2.40 per MMBtu with Enron. The volumes presented in this table are divided equally over the months during the period.

VOLUME PERIOD BEGINNING PERIOD ENDING (MMBtu) ---------------- ----------------- --------- May 1, 1998 December 31, 1998 2,210,000 January 1, 1999 December 31, 1999 2,710,000 January 1, 2000 December 31, 2000 2,200,000 January 1, 2001 December 31, 2001 1,850,000 January 1, 2002 December 31, 2002 1,600,000 January 1, 2003 December 31, 2003 1,400,000

Effective November 1, 1999, the Company unwound the ceiling price limitation of this collar at a cost of $3.3 million. The table below sets out volumes of natural gas that remains under contract at a floor price of $2.00 per MMBtu. The volumes presented in this table are divided equally over the months during the period.

VOLUME PERIOD BEGINNING PERIOD ENDING (MMBtu) ---------------- ----------------- --------- November 1, 1999 December 31, 1999 722,000 January 1, 2000 December 31, 2000 3,520,000 January 1, 2001 December 31, 2001 2,970,000 January 1, 2002 December 31, 2002 2,550,000 January 1, 2003 December 31, 2003 2,250,000

F-15 63 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 5. DERIVATIVES AND HEDGING ACTIVITIES (CONTINUED) During the years ended December 31, 2000, 1999 and 1998, the Company recognized hedging gains (losses) of approximately $(3,324,000), $644,000 and $803,000, respectively, relating to cash settlements under these agreements, which are included in net profits and royalty interests revenues. During the year ended December 31, 1998, the Company entered into a swap agreement with Enron to hedge 12,000 barrels of oil production monthly at $17.00 per barrel, for the months of October, November and December 1998. The Company recognized hedging gains of approximately $147,000 relating to this agreement, which are included in net profits and royalty interests revenues. During the year ended December 31, 1999, the Company entered into a swap agreement with Enron to hedge 10,000 barrels of oil production monthly at $13.50 per barrel for the six months March through August 1999, and for 5,000 barrels of oil production monthly at $14.35 per barrel, and for 5,000 barrels of oil production monthly at $14.82 per barrel for the six months April through September 1999. During the year ended December 31, 1999, the Company recognized hedging losses of approximately $589,000 relating to this agreement, which are included in net profits and royalty interests revenues. The table below sets out volumes of oil hedged with a collar with Enron involving floor and ceiling prices as set out in the table below. The volumes presented in this table are divided equally over the months during the period.

VOLUME FLOOR CEILING PERIOD BEGINNING PERIOD ENDING (MMBtu) PRICE PRICE ---------------- ----------------- ------ ------ --------- December 1, 1999 March 31, 2000 40,000 $22.90 $25.77 April 1, 2000 June 30, 2000 15,000 $23.00 $28.16 July 1, 2000 December 31, 2000 30,000 $22.00 $28.63

During the years ended December 31, 2000 and 1999, the Company recognized hedging losses of approximately $3,000 and $203,000, respectively, relating to this contract. During the year ended December 31, 2000, the Company entered into a series of collars to hedge a portion of future natural gas production involving floor and ceiling prices as set out below. The volumes presented in this table are divided equally over the months during the period.

VOLUME FLOOR CEILING PERIOD BEGINNING PERIOD ENDING (MMBtu) PRICE PRICE ---------------- ----------------- ------ ------ --------- January 1, 2001 March 31, 2001 1,125,000 $5.44 $8.29 April 1, 2001 June 30, 2001 675,000 $4.07 $6.42 July 1, 2001 December 31, 2001 1,350,000 $4.07 $6.51

The aggregate fair value of the Company's derivative contracts at December 31, 2000 represented a net liability of $13,540,000. The Company entered into a forward LIBOR interest rate swap effective for the period June 30, 1998 through June 29, 2009 at a rate of 6.3% on $125 million, which could be unwound at any time at the option of the Company. On July 9, 1998, as a result of the retirement of the Bridge Facilities and borrowings under the Credit Agreement, the F-16 64 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 5. DERIVATIVES AND HEDGING ACTIVITIES (CONTINUED) Company terminated the agreement at a cost of $3,549,000. The cost of termination has been reflected as an extraordinary loss in the accompanying consolidated statement of operations for the year ended December 31, 1998. 6. STOCKHOLDERS' EQUITY GENERAL The Company's Certificate of Incorporation authorizes the issuance of: (a) 50,000,000 shares of preferred stock of the Company, par value $.01 per share (the Preferred Stock), of which 9,600,000 shares have been designated as Series A Preferred Stock, 9,600,000 shares have been designated as Series B Preferred Stock and 10,400 shares have been designated as Series C Preferred Stock and (b) 100,000,000 shares of Common Stock, par value $0.234. Any authorized but unissued or unreserved Common Stock and undesignated Preferred Stock is available for issuance at any time, on such terms and for such purposes as the Board of Directors may deem advisable in the future without further action by stockholders of the Company, except as may be required by law or the Series A or Series C Certificate of Designation. The Board of Directors of the Company has the authority to fix the rights, powers, designations and preferences of the undesignated Preferred Stock and to provide for one or more series of undesignated Preferred Stock. The authority will include, but will not be limited to: determination of the number of shares to be included in the series; dividend rates and rights; voting rights, if any; conversion privileges and terms; redemption conditions; redemption values; sinking funds; and rights upon involuntary or voluntary liquidation. In connection with the Recapitalization, the Company implemented a 156-to-1 reverse split of its common stock which reduced the total number of shares of common stock outstanding from 80,688,538 pre-split shares (par value $0.0015) to 517,234 post-split shares (par value $0.234). In connection with the Recapitalization, the holders of the Series A Preferred Stock and the Series C Preferred Stock and common stock repricing rights exchanged all their remaining shares of the Series A Preferred Stock, Series C Preferred Stock and common stock repricing rights, together with all their respective warrants and non-dilution rights for an aggregate of 732,500 shares of post reverse-split common stock. As of December 31, 2000, there were no shares of Preferred Stock, no common stock repricing rights, no stock purchase warrants and 12,748,612 shares of common stock outstanding. SERIES A PREFERRED STOCK In March 1997, the Company entered into a Securities Purchase Agreement with Joint Energy Development Limited Partnership II, an affiliate of Enron (respectively the "JEDI Purchase Agreement and "JEDI") under which JEDI acquired 9,600,000 shares of Series A Preferred Stock, certain warrants to purchase common stock and nondilution rights in regards to future stock issuances by the Company. The aggregate consideration received by the Company consisted of $5,000,000. In connection with the Recapitalization, JEDI accepted 212,500 shares of post reverse-split common stock in exchange for all 9,600,000 shares of Series A Preferred Stock and stock warrants that it then held, and the surrender of all its remaining nondilution and other rights under the JEDI Purchase Agreement. As a result of that transaction, the JEDI Purchase Agreement was terminated. As of December 31, 2000, there were no shares of Series A Preferred Stock outstanding. F-17 65 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 6. STOCKHOLDERS' EQUITY (CONTINUED) SERIES B PREFERRED STOCK No shares of Series B Preferred Stock have been issued. SERIES C PREFERRED STOCK In December 1997, the Company sold 10,000 shares of Series C Preferred Stock to various investors in a private placement for gross proceeds of $10,000,000. The investors also received warrants to purchase 2,180 shares of common stock in the transaction. The Company issued an additional 400 shares of Series C Preferred Stock in consideration of placement agent fees incurred with respect to the transaction. During the year ended December 31, 1998, the Company repurchased for cash a total of 2,152 shares of Series C Preferred Stock. In addition, an aggregate of 2,290 shares of Series C Preferred Stock was converted into 2,534 shares of common stock and 111 shares of common stock were issued in payment of dividends that had accrued in respect of the 2,290 shares of Series C Preferred Stock that were converted during the year. During the year ended December 31, 1999, an aggregate of 1,710 shares of Series C Preferred Stock was converted into 12,642 shares of common stock. In addition, 957 shares of common stock were issued in payment of dividends that had accrued in respect of the 1,710 shares of Series C Preferred Stock that were converted during the year. During the year ended December 31, 2000, an aggregate of 2,075 shares of Series C Preferred Stock was converted into 46,019 shares of common stock. In addition, 5,293 shares of common stock were issued in payment of dividends that had accrued in respect of the 2,075 shares of Series C Preferred Stock that were converted during the year. In connection with the Recapitalization, the Company issued 120,000 shares of common stock in exchange for the 2,173 shares of Series C Preferred Stock that remained outstanding at the time plus the warrants. As of December 31, 2000, there were no shares of Series C Preferred Stock or related stock purchase warrants outstanding. COMMON STOCK During 1998, the Company completed the private placement of an aggregate of 34,013 shares of the Company's Common Stock for aggregate net proceeds of approximately $26,980,000 (the Equity Offerings). In connection with the sale of 24,841 shares in the Equity Offerings, the Company granted certain common stock reset rights (the Repricing Rights) for each share sold. Each Repricing Right granted the holder the right to receive, in certain circumstances, additional shares of common stock for no consideration. Additionally, warrants to purchase an aggregate of 8,278 shares of the Company's common stock were granted to purchasers of common stock. During 1998, 15,860 shares of common stock were issued upon the exercise of certain stock purchase warrants. The Company received aggregate net proceeds of $7,000,000 from these exercises. During 1998, the Company issued a total of 4,984 shares of common stock pursuant to the exercise of 6,939 Repricing Rights. During 1999, the Company issued a total of 19,245 shares of common stock pursuant to the exercise of 1,294 Repricing Rights. In 2000, the Company issued a total of 228,962 shares of common stock pursuant to the exercise of 6,199 Repricing Rights. F-18 66 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 6. STOCKHOLDERS' EQUITY (CONTINUED) In connection with the Recapitalization, the holders of all remaining Repricing Rights exchanged all their remaining Repricing Rights, together with all outstanding warrants that had been issued as part of the Equity Offerings, for an aggregate of 400,000 shares of common stock. As of December 31, 2000, there were no Repricing Rights or stock purchase warrants outstanding. STOCK OPTIONS

YEAR ENDED DECEMBER 31 --------------------------------------------------------------------- 2000 1999 1998 --------------------- ------------------- ------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE -------- --------- ------- --------- ------- --------- Outstanding at January 1 4,894 $1,071.04 4,894 $1,071.04 1,173 $ 819.00 Granted 732,500 7.01 -- -- 3,721 1,150.50 Exercised -- -- -- -- -- -- Canceled (4,894) 1,071.04 -- -- -- -- -------- ----- ---- Outstanding at December 31 732,500 $ 7.01 4,894 $1,071.04 4,894 $1,071.04 ======== ===== ===== Exercisable options outstanding at December 31 -- $ -- 640 $ 998.65 293 $ 819.00 ======== ===== =====

The weighted average grant date fair values of stock options granted during 2000 and 1998 were $2.10 and $971.88, respectively. The grant date fair values were estimated at the date of grant using the Black-Scholes option pricing model. As of December 31, 2000, the weighted average remaining contractual life of outstanding stock options was 9.8 years. Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), requires the disclosure of pro forma net income and earnings per share information computed as if the Company had accounted for its employee stock options under the fair value method set forth in SFAS 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, respectively: a risk-free interest rate of 5.75% and 6.00% during 2000 and 1998, respectively; a dividend yield of 0%; and a volatility factor of 0.256 and 0.792 during 2000 and 1998, respectively. In addition, the fair value of these options was estimated based on an expected weighted average life of 4 years and 10 years during 2000 and 1998, respectively. 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. F-19 67 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 6. STOCKHOLDERS' EQUITY (CONTINUED) 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 -------------------------------------------- 2000 1999 1998 ----------- ------------- ------------- Pro forma net income/(loss) $22,797,000 $(12,573,000) $(74,674,000) Basic income/(loss) per share $ 9.64 $ (58.41) $ (435.81) Diluted income/(loss) per share $ 7.50 $ (58.41) $ (435.81)

7. FAIR VALUE OF FINANCIAL INSTRUMENTS The Company defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. The carrying value of accounts receivable, accounts payable and accrued liabilities approximates fair value because of the short maturity of those instruments. The estimated fair value of the Company's long-term obligations is estimated based on the current rates offered to the Company for similar maturities. At December 31, 2000, 1999 and 1998, the carrying value of long-term obligations exceeded their fair values by approximately $14,500,000, $62,500,000 and $22,500,000, respectively. The estimated fair value of the Company's derivative contracts at December 31, 2000 represented a net liability of approximately $13,540,000. 8. RELATED PARTY TRANSACTIONS The Company has entered into various hedging arrangements with affiliates of Enron (Note 4). The Company had entered into a revolving credit facility with ECT, an affiliate of Enron. During the year ended December 31, 1998, commitment fees of approximately $200,000 and interest totaling approximately $9,000 were paid to ECT in connection with this facility. This agreement was terminated in October 1999. Enron, through its affiliates, participated in indebtedness incurred in connection with the acquisition of the Morgan Properties. During the year ended December 31, 1999, Enron received interest payments of approximately $286,000 from the Company relating to such participation. The Company paid Enron approximately $75,000 and $100,000 during the years ended December 31, 2000 and 1999, respectively, under the terms of an agreement which allows the Company to consult, among other things, with Enron's engineering staff. F-20 68 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 9. INCOME TAXES The provision (benefit) for income taxes attributable to continuing operations is as follows:

YEAR ENDED DECEMBER 31 ---------------------------------------- 2000 1999 1998 ----------- ----------- ----------- Current $ 782,000 $ -- $ -- Deferred (1,424,000) -- -- ----------- ----------- ----------- $ (642,000) $ -- $ -- =========== =========== ===========

The provision for income taxes differs from amounts computed at the statutory federal income tax rate for the year ended December 31, 2000 as follows: Statutory income tax provision $ 716,000 State income taxes, net of federal benefit 63,000 Change in valuation allowance (1,221,000) Utilization of net operating loss carryforwards (203,000) Other, net 3,000 ----------- $ (642,000) =========== The Company's effective tax rate differs from the U.S. statutory rate for each of the years ended December 31, 1999 and 1998 due to losses for which no deferred tax benefit was recognized. The tax effects of the primary temporary differences giving rise to the deferred federal income tax assets and liabilities at December 31, 2000 and 1999, follow:

2000 1999 ------------ ------------ Deferred income tax assets (liabilities): Unrealized derivative losses $ 5,097,000 $ -- Net operating loss carryforwards 8,116,000 21,576,000 Oil and gas properties, principally due to differences in depreciation and amortization 212,000 3,438,000 Other (3,000) (76,000) ------------ ------------ 13,422,000 24,938,000 Less valuation allowance (12,201,000) (24,938,000) ------------ ------------ Net deferred income tax asset $ 1,221,000 $ -- ============ ============

The net changes in the total valuation allowance for the years ended December 31, 2000 and 1999 were a decrease and an increase of $12,737,000 and $3,000,000, respectively. The Company's net operating loss carryforwards (NOLs) begin expiring in 2018. The Company is limited to an annual utilization of its NOLs of approximately $1,100,000 as a result of the Recapitalization. To the extent that the Company utilizes in the future NOLs existing as of the date of the Recapitalization but which were not recognized as deferred tax assets prior to the Recapitalization, the benefit of the NOLs will be credited to additional paid-in capital. During 2000, the Company utilized NOLs approximating $68,000 (tax effected), which was credited to additional paid-in capital. F-21 69 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 9. INCOME TAXES (CONTINUED) During 2000, NOLs of approximately $21,144,000 were used to offset taxable income associated with the extraordinary gain recognized upon the retirement of $75,000,000 of Notes (Note 4). 10. COMMITMENTS AND CONTINGENCIES The Company is involved in certain disputes and other matters arising in the normal course of business. Although the ultimate resolution of these matters cannot be reasonably estimated at this time, management does not believe that they will have a material adverse effect on the financial condition or results of operations of the Company. 11. OIL AND GAS PRODUCING ACTIVITIES The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with Statement of Financial Accounting Standards No. 69. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES The following sets forth certain information with respect to results of operations from oil and gas producing activities for the years ended December 31, 2000, 1999 and 1998:

2000 1999 1998 ------------ ------------ ------------ Oil and gas sales $ 4,484,000 $ 3,625,000 $ 5,852,000 Net profits and royalty interests revenues 31,507,000 21,955,000 15,947,000 Production expenses (1,727,000) (1,622,000) (4,326,000) Depreciation and amortization (8,560,000) (9,281,000) (10,749,000) Write-down of oil and gas properties -- -- (63,199,000) ------------ ------------ ------------ Results of operations (excludes corporate overhead and interest expense) $ 25,704,000 $ 14,677,000 $(56,475,000) ============ ============ ============

Depreciation and amortization of oil and gas properties was $0.78, $0.70, and $0.85 per Mcfe produced for the years ended December 31, 2000, 1999 and 1998, respectively. The following table summarizes capitalized costs relating to oil and gas producing activities and related amounts of accumulated depreciation and amortization at December 31, 2000 and 1999:

2000 1999 ------------- ------------- Oil and gas properties - proved $ 191,204,000 $ 181,549,000 Accumulated depreciation and amortization (94,214,000) (85,771,000) ------------- ------------- Net capitalized costs $ 96,990,000 $ 95,778,000 ============= =============

F-22 70 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 11. OIL AND GAS PRODUCING ACTIVITIES (CONTINUED) COSTS INCURRED The following sets forth certain information with respect to costs incurred, whether expensed or capitalized, in oil and gas activities for the years ended December 31, 2000, 1999 and 1998:

2000 1999 1998 ------------ ------------- ------------ Property acquisition costs $ -- $ -- $141,262,000 ============ ============= ============ Development costs $ 13,043,000 $ 7,494,000 $ 12,699,000 ============ ============= ============

12. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) RESERVE QUANTITY INFORMATION The following table presents the Company's estimate of its proved oil and gas reserves, all of which are located in the United States. The Company 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 at December 31, 1999 and 2000 have been prepared by independent petroleum reservoir engineers. The estimates at December 31, 1997 and 1998 have been prepared by the Company's petroleum engineers.

OIL (Bbls) GAS (Mcf) ------------ ------------ Proved reserves: Balance at December 31, 1997 7,115,000 20,979,000 Purchases of minerals in place 3,579,000 160,913,000 Revisions of previous estimates and other (3,334,000) 44,000 Production 481,000 9,931,000 ------------ ------------ Balance at December 31, 1998 6,879,000 172,005,000 Sales of minerals in place (2,735,000) (18,243,000) Revisions of previous estimates and other 648,000 (2,323,000) Production 339,000 11,441,000 ------------ ------------ Balance at December 31, 1999 4,453,000 139,998,000 Sales of minerals in place (1,000) (7,035,000) Revisions of previous estimates and other (2,875,000) 6,610,000 Production 216,000 9,797,000 ------------ ------------ Balance at December 31, 2000 1,361,000 129,776,000 ============ ============ Proved developed reserves: Balance at December 31, 1997 2,352,000 12,566,000 ============ ============ Balance at December 31, 1998 4,317,000 120,373,000 ============ ============ Balance at December 31, 1999 1,937,000 86,044,000 ============ ============ Balance at December 31, 2000 1,253,000 84,669,000 ============ ============

F-23 71 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 12. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) (CONTINUED) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standards No. 69. The Standardized Measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties and consideration of expected future economic and operating conditions. Under the Standardized Measure, future cash flows are estimated by applying year-end prices, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pretax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pretax cash inflows over the Company's tax basis in the associated properties. Tax credits, net operating loss carryforwards and permanent differences are also considered in the future tax calculation. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure. The Standardized Measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31, 2000 and 1999, is as follows:

2000 1999 --------------- --------------- Future cash inflows $ 1,451,177,000 $ 435,370,000 Future costs and expenses: Production expenses (223,812,000) (133,463,000) Development costs (21,441,000) (24,984,000) Future income taxes (370,200,000) (30,500,000) --------------- --------------- Future net cash flows 835,724,000 246,423,000 10% annual discount for estimated timing of cash flows (465,502,000) (129,744,000) --------------- --------------- Standardized Measure of discounted future net cash flows $ 370,222,000 $ 116,679,000 =============== ===============

F-24 72 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 12. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED) (CONTINUED) Changes in the Standardized Measure of discounted future net cash flows relating to proved oil and gas reserves for the years ended December 31, 2000, 1999 and 1998 are as follows:

2000 1999 1998 ------------- ------------- ------------- Beginning balance $ 116,679,000 $ 108,287,000 $ 28,111,000 Purchases of minerals in place -- -- 135,418,000 Sales of minerals in place (12,953,000) (16,035,000) -- Developed during the period 13,043,000 7,494,000 12,699,000 Net change in prices and costs 501,474,000 62,102,000 (70,744,000) Revisions of previous estimates (74,940,000) (21,368,000) 6,665,000 Accretion of discount 11,668,000 10,829,000 2,811,000 Net change in income taxes (150,485,000) (10,672,000) 10,800,000 Sales of oil and gas produced, net of production expenses (34,264,000) (23,958,000) (17,473,000) ============= ============= ============= Balance at December 31 $ 370,222,000 $ 116,679,000 $ 108,287,000 ============= ============= =============

The weighted average prices of oil and gas used in calculating the Standardized Measure at December 31, 2000, 1999 and 1998 were as follows:

2000 1999 1998 -------- -------- -------- Natural gas (Per MCF) $ 10.92 $ 2.35 $ 1.84 Oil (per Bbl) $ 25.88 $ 23.91 $ 10.79

The future cash flows shown above for 2000 include amounts attributable to proved undeveloped reserves requiring approximately $20,648,000 of future development costs. If these reserves are not developed, the future net cash flows shown above would be significantly reduced. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Therefore, actual production, revenues, taxes, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated. F-25 73 DEVX ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 13. QUARTERLY FINANCIAL RESULTS (UNAUDITED)

2000 ------------------------------------------------------------ MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ------------ ------------ ------------ ------------ Total revenues $ 6,673,000 $ 8,231,000 $ 10,276,000 $ 10,901,000 Operating income $ 6,101,000 $ 7,709,000 $ 9,812,000 $ 10,732,000 Income (loss) before extraordinary item and cumulative effect of accounting change $ (1,618,000) $ 190,000 $ 1,377,000 $ 2,704,000 Extraordinary gain $ -- $ -- $ 21,144,000 Cumulative effect of accounting change, net of tax $ -- $ -- $ 413,000 $ -- Net income (loss) $ (1,618,000) $ 190,000 $ 1,790,000 $ 23,848,000 Income (loss) before extraordinary item and cumulative effect of accounting change per common share $ (5.59) $ 0.15 $ 0.83 $ 0.30 Net income (loss) per common share $ (5.59) $ 0.15 $ 1.08 $ 2.69

1999 ------------------------------------------------------------ MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ------------ ------------ ------------ ------------ Total revenues $ 6,734,000 $ 6,986,000 $ 5,543,000 $ 6,653,000 Operating income $ 6,015,000 $ 6,363,000 $ 5,385,000 $ 6,533,000 Loss before extraordinary item $ (1,977,000) $ (2,183,000) $ (2,242,000) $ (4,258,000) Extraordinary loss $ -- $ -- $ -- $ (1,130,000) Net loss $ (1,977,000) $ (2,183,000) $ (2,242,000) $ (5,388,000) Loss before extraordinary item per common share $ (0.06) $ (0.07) $ (0.07) $ (0.12) Net loss per common share $ (0.06) $ (0.07) $ (0.07) $ (0.15)

F-26 74 EXHIBIT INDEX

EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 Restated Certificate of Incorporation of the Company, filed as Exhibit 4.5 to the Company's Registration Statement on Form S-3 (No. 333-47577) filed with the Securities and Exchange Commission on March 9, 1998, which Exhibit is incorporated herein by reference 3.2 Certificate of Designation of Series C Convertible Preferred Stock of the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated December 24, 1997, which Exhibit is incorporated herein by reference. 3.3 Certificate of Amendment to the Restated Certificate of Incorporation of the Company, filed with the Secretary of State for the State of Delaware on September 19, 2000 which Certificate was filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated herein by reference. 3.4* Certificate of Amendment to the Restated Certificate of Incorporation of the Company, filed with the Secretary of State for the State of Delaware on October 26, 2000, which Certificate is filed herewith. 3.5 Amended and Restated Bylaws of the Company, filed as an Exhibit to the Company's Current Report on Form 8-K dated March 27, 1997, which Exhibit is incorporated herein by reference. 4.1 Indenture, dated July 1, 1998, in regard to 12 1/2% Senior Notes due 2008 by and among the Company and certain of its subsidiaries and Harris Trust and Savings Bank, as Trustee, filed as an Exhibit to the Company's Current Report on Form 8-K dated July 8, 1998, which Exhibit is incorporated herein by reference. 4.2* First Supplement to Indenture dated October 12, 2000 among the Company, certain of its subsidiaries and Harris Trust and Savings Bank as Trustee, which Exhibit is filed herewith. 4.3 Settlement Agreement dated as of July 17, 2000 between the Company and the stockholders named therein, filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated herein by reference. 4.4 Participation Agreement dated as of July 17, 2000 between the Company and the holders of its 12 1/2% senior notes therein filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992) which Exhibit is incorporated herein by reference. 4.5 Amendment to Participation Agreement dated as of October 4, 2000 between the Company and certain holders of its 12 1/2% senior notes therein filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated herein by reference 10.1 Queen Sand Resources 1997 Incentive Equity Plan, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998, which Exhibit is incorporated herein by reference. 10.2* Form of DevX Energy, Inc. Restated and Amended Incentive Equity Plan filed herewith**. 10.3* Form of Option Agreement issued under the Amended and Restated Incentive Equity Plan filed herewith**.

75 10.4 Directors' Non-Qualified Stock Option Plan filed as Appendix A to the Company's Definitive Proxy Statement on Schedule 14A dated October 23, 1998, which Exhibit is incorporated herein by reference**. 10.5* Form of DevX Energy, Inc. Restated and Amended Directors' Non-Qualified Stock Option Plan filed herewith**. 10.6* Form of Option Agreement issued under the Amended and Restated Directors' Non-Qualified Stock Option Plan filed herewith**. 10.7 Amended and Restated Credit Agreement among the Company, DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, effective as of October 22, 1999, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.8 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by the Company as Guarantor in favor of Ableco Finance LLC, as Collateral Agent for the lender group and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.9 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by DevX Operating Company a Nevada corporation, (formerly known as Queen Sand Operating Co.), as Guarantor, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.10 Second Amended And Restated Guaranty Agreement dated as of October 22, 1999 by Corrida Resources, Inc. as Guarantor, in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.11 Security Agreement dated as of October 22, 1999, by and among the Company, DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), DevX Operating Company (formerly known as Queen Sand Operating Co.), Corrida Resources, Inc. and Ableco Finance LLC, as collateral agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.12 Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.13 Second Amended and Restated Pledge and Security Agreement dated as of October 22, 1999, by the Company in favor of Ableco Finance LLC, as Collateral Agent for the lender group, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999. 10.14 Amendment No. 1 to Credit Agreement dated May 2000 among the Company, DevX Energy, Inc., a Nevada corporation (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 (No. 333-41992), which Exhibit is incorporated by reference. 10.15 Amendment No. 2 to Credit Agreement dated June 30, 2000 among the Company, DevX Energy, Inc., a Nevada corporation, (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000, (No. 333-41992), which Exhibit is incorporated by reference. 10.16 Amendment No. 3 to Credit Agreement dated September , 2000 among the Company, DevX Energy, Inc., a Nevada corporation (formerly known as Queen Sand Resources, Inc.), Ableco Finance LLC, 76 as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated by reference. 10.17 Amendment No. 4 to Credit Agreement dated October 24, 2000 among the Company, DevX Energy, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, filed as an Exhibit to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000, which Exhibit is incorporated by reference. 10.18* Amendment No. 5 to Credit Agreement dated January 31, 2001 among the Company, DevX Energy, Inc., a Nevada corporation, Ableco Finance LLC, as Collateral Agent, and the lenders signatory thereto, which Amendment is filed herewith. 10.19* Employment Agreement dated as of October 6, 2000 between the Company and Joseph T. Williams which agreement is filed herewith**. 10.20* Form of Directors' Indemnity Agreement signed by Jerry B. Davis and Robert L. Keiser.** 10.21 Employment Agreement dated December 15, 1997 between the Company and Robert P. Lindsay, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference**. 10.22* Release Agreement dated December 7, 2000 between the Company and Robert P. Lindsay which agreement is filed herewith**. 10.23 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Bruce I. Benn, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference**. 10.24* Release Agreement dated December 7, 2000 between the Company and Bruce I. Benn which agreement is filed herewith**. 10.25 Employment Agreement dated December 15, 1997 among the Company, Queen Sand Resources (Canada) Inc. and Ronald Benn, filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1998 (No. 333-61403) which Exhibit is incorporated herein by reference**. 10.26 Release Agreement dated September 15, 2000 between the Company and Ronald I. Benn filed as an Exhibit to the Company's Registration Statement on Form S-2 filed with the Securities and Exchange Commission on October 6, 2000 (No. 333-41992), which Exhibit is incorporated by reference**. 10.27* Employment Agreement dated as of November 10, 2000 between the Company and Edward J. Munden which agreement is filed herewith**. 10.28* Employment Agreement dated as of November 10, 2000 between the Company and William W. Lesikar which agreement is filed herewith**. 10.29* Employment Agreement dated as of November 10, 2000 between the Company and Brian J. Barr which agreement is filed herewith**. 21.1 List of the subsidiaries of the registrant filed as an Exhibit to the Company's Registration Statement on Form S-4 filed with the Securities and Exchange Commission on August 13, 1999 (No. 333-61403) which Exhibit is incorporated by reference. 23.1* Consent of Ernst & Young LLP. 23.2* Consent of Ryder Scott Company. 23.3* Consent of H.J. Gruy and Associates, Inc. ----------- * Indicates Filed herewith. ** Indicates Management Contract